UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
______________________
Form 10-K
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(Mark
One)
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R
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
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FOR
THE FISCAL YEAR ENDED DECEMBER 31, 2009
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OR
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£
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
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FOR THE TRANSITION
PERIOD FROM
TO
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Commission
File Number 1-31447
______________________
CenterPoint Energy,
Inc.
(Exact
name of registrant as specified in its charter)
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Texas
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74-0694415
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(State
or other jurisdiction of incorporation or organization)
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(I.R.S.
Employer Identification No.)
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1111
Louisiana
Houston,
Texas 77002
(Address
and zip code of principal executive offices)
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(713)
207-1111
(Registrant’s
telephone number, including area
code)
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Securities
registered pursuant to Section 12(b) of the Act:
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Title
of each class
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Name
of each exchange on which registered
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Common
Stock, $0.01 par value and associated
rights
to purchase preferred stock
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New
York Stock Exchange
Chicago
Stock Exchange
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Securities
registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required
to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant:
(1) has filed all reports required to be filed by Section 13 or 15(d)
of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past
90 days. Yes þ No o
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes þ No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein and
will not be contained, to the best of each of the registrants’ knowledge, in
definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this
Form 10-K. þ
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
definitions of "large accelerated filer", "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act. (Check
one):
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Large accelerated
filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o
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(Do
not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell
company (as defined in Rule 12b-2 of the Exchange
Act). Yes o No þ
The
aggregate market value of the voting stock held by non-affiliates of CenterPoint
Energy, Inc. (CenterPoint Energy) was $4,008,560,260 as of June 30, 2009,
using the definition of beneficial ownership contained in Rule 13d-3
promulgated pursuant to the Securities Exchange Act of 1934 and excluding shares
held by directors and executive officers. As of February 15, 2010, CenterPoint
Energy had 392,717,790 shares of Common Stock outstanding. Excluded from
the number of shares of Common Stock outstanding are 166 shares held by
CenterPoint Energy as treasury stock.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the definitive proxy statement relating to the 2010 Annual Meeting of
Shareholders of CenterPoint Energy, which will be filed with the Securities and
Exchange Commission within 120 days of December 31, 2009, are
incorporated by reference in Item 10, Item 11, Item 12,
Item 13 and Item 14 of Part III of this
Form 10-K.
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Page
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PART I
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Item 1.
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1
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Item 1A.
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23
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Item 1B.
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34
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Item 2.
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34
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Item 3.
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35
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Item 4.
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PART II
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Item 5.
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36
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Item 6.
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Item 7.
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38
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Item 7A.
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62
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Item 8.
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64
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Item 9.
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113
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Item 9A.
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113
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Item 9B.
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114
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PART III
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Item 10.
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114
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Item 11.
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114
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Item 12.
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114
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Item 13.
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114
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Item 14.
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114
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PART IV
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Item 15.
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114
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| Ex. 10(kk)(2) | Form of Qualified Performance Award Agreement for 20XX - 20XX Performance Cycle under Exhibit 10(kk)(1) | |
| Ex. 10(kk)(3) | Form of Restricted Stock Unit Award Agreement (With Performance Goal) under Exhibit 10(kk)(1) | |
| Ex. 10(ll) | ||
| Ex. 10(mm) | ||
| Ex. 12 | ||
| Ex. 21 | ||
| Ex. 23 | ||
| Ex. 31.1 | ||
| Ex. 31.2 | ||
| Ex. 32.1 | ||
| Ex. 32.2 | ||
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING INFORMATION
From time
to time we make statements concerning our expectations, beliefs, plans,
objectives, goals, strategies, future events or performance and underlying
assumptions and other statements that are not historical facts. These statements
are "forward-looking statements" within the meaning of the Private Securities
Litigation Reform Act of 1995. Actual results may differ materially from those
expressed or implied by these statements. You can generally identify our
forward-looking statements by the words "anticipate," "believe," "continue,"
"could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective,"
"plan," "potential," "predict," "projection," "should," "will" or other similar
words.
We have
based our forward-looking statements on our management’s beliefs and assumptions
based on information available to our management at the time the statements are
made. We caution you that assumptions, beliefs, expectations, intentions and
projections about future events may and often do vary materially from actual
results. Therefore, we cannot assure you that actual results will not differ
materially from those expressed or implied by our forward-looking
statements.
Some of
the factors that could cause actual results to differ from those expressed or
implied by our forward-looking statements are described under "Risk Factors" in
Item 1A of this report.
You
should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular
statement.
PART I
Item 1. Business
OUR
BUSINESS
Overview
We are a public utility holding company whose indirect wholly owned subsidiaries
include:
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CenterPoint
Energy Houston Electric, LLC (CenterPoint Houston), which engages in the
electric transmission and distribution business in a 5,000-square mile
area of the Texas Gulf Coast that includes the city of
Houston; and
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CenterPoint
Energy Resources Corp. (CERC Corp. and, together with its subsidiaries,
CERC), which owns and operates natural gas distribution systems in six
states. Subsidiaries of CERC Corp. own interstate natural gas pipelines
and gas gathering systems and provide various ancillary services. A wholly
owned subsidiary of CERC Corp. offers variable and fixed-price physical
natural gas supplies primarily to commercial and industrial customers and
electric and gas utilities.
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Our
reportable business segments are Electric Transmission & Distribution,
Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate
Pipelines, Field Services and Other Operations. From time to time, we consider
the acquisition or the disposition of assets or businesses.
Our
principal executive offices are located at 1111 Louisiana, Houston, Texas 77002
(telephone number: 713-207-1111).
We make
available free of charge on our Internet website our annual report on
Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after we electronically file such reports with, or
furnish them to, the Securities and Exchange Commission (SEC). Additionally, we
make available free of charge on our Internet website:
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our
Code of Ethics for our Chief Executive Officer and Senior Financial
Officers;
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our
Ethics and Compliance Code;
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our
Corporate Governance Guidelines;
and
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the
charters of the audit, compensation, finance, governance and strategic
planning committees of our Board of
Directors.
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Any
shareholder who so requests may obtain a printed copy of any of these documents
from us. Changes in or waivers of our Code of Ethics for our Chief Executive
Officer and Senior Financial Officers and waivers of our Ethics and Compliance
Code for directors or executive officers will be posted on our Internet website
within five business days of such change or waiver and maintained for at least
12 months or reported on Item 5.05 of Form 8-K. Our website
address is www.centerpointenergy.com.
Except to the extent explicitly stated herein, documents and information
on our website are not incorporated by reference herein.
Electric
Transmission & Distribution
In 1999,
the Texas legislature adopted the Texas Electric Choice Plan (Texas electric
restructuring law) that led to the restructuring of certain integrated electric
utilities operating within Texas. Pursuant to that legislation, integrated
electric utilities operating within the Electric Reliability Council of Texas,
Inc. (ERCOT) were required to unbundle their integrated operations into separate
retail sales, power generation and transmission and distribution companies. The
legislation also required that the prices for wholesale generation and retail
electric sales be unregulated, but
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services
by companies providing transmission and distribution service, such as
CenterPoint Houston, would remain regulated by the Public Utility Commission of
Texas (Texas Utility Commission). The legislation provided for a transition
period to move to the new market structure and provided a true-up mechanism for
the formerly integrated electric utilities to recover stranded and certain other
costs resulting from the transition to competition. Those costs were recoverable
after approval by the Texas Utility Commission either through the issuance of
securitization bonds or through the implementation of a competition transition
charge (CTC) as a rider to the utility’s tariff.
CenterPoint
Houston is our only business that continues to engage in electric utility
operations. It is a transmission and distribution electric utility that operates
wholly within the state of Texas. Neither CenterPoint Houston nor any other
subsidiary of CenterPoint Energy makes retail or wholesale sales of electric
energy, or owns or operates any electric generating facilities.
Electric
Transmission
On behalf
of retail electric providers (REPs), CenterPoint Houston delivers electricity
from power plants to substations, from one substation to another and to retail
electric customers taking power at or above 69 kilovolts (kV) in locations
throughout CenterPoint Houston’s certificated service territory. CenterPoint
Houston constructs and maintains transmission facilities and provides
transmission services under tariffs approved by the Texas Utility
Commission.
Electric
Distribution
In ERCOT,
end users purchase their electricity directly from certificated REPs.
CenterPoint Houston delivers electricity for REPs in its certificated service
area by carrying lower-voltage power from the substation to the retail electric
customer. CenterPoint Houston’s distribution network receives electricity from
the transmission grid through power distribution substations and delivers
electricity to end users through distribution feeders. CenterPoint Houston’s
operations include construction and maintenance of distribution facilities,
metering services, outage response services and call center operations.
CenterPoint Houston provides distribution services under tariffs approved by the
Texas Utility Commission. Texas Utility Commission rules and market protocols
govern the commercial operations of distribution companies and other market
participants. Rates for these existing services are established pursuant to rate
proceedings conducted before municipalities that have original jurisdiction and
the Texas Utility Commission.
ERCOT
Market Framework
CenterPoint
Houston is a member of ERCOT. ERCOT serves as the regional reliability
coordinating council for member electric power systems in Texas. ERCOT
membership is open to consumer groups, investor and municipally-owned electric
utilities, rural electric cooperatives, independent generators, power marketers
and REPs. The ERCOT market includes most of the State of Texas, other than a
portion of the panhandle, portions of the eastern part of the state bordering
Arkansas and Louisiana and the area in and around El Paso. The ERCOT market
represents approximately 85% of the demand for power in Texas and is one of the
nation’s largest power markets. The ERCOT market includes an aggregate net
generating capacity of approximately 76,000 megawatts (MW). There are only
limited direct current interconnections between the ERCOT market and other power
markets in the United States and Mexico.
The ERCOT
market operates under the reliability standards set by the North American
Electric Reliability Corporation (NERC) and approved by the Federal Energy
Regulatory Commission (FERC). These reliability standards are administered by
the Texas Regional Entity (TRE), a functionally independent division of ERCOT.
The Texas Utility Commission has primary jurisdiction over the ERCOT market to
ensure the adequacy and reliability of electricity supply across the state’s
main interconnected power transmission grid. The ERCOT independent system
operator (ERCOT ISO) is responsible for operating the bulk electric power supply
system in the ERCOT market. Its responsibilities include ensuring that
electricity production and delivery are accurately accounted for among the
generation resources and wholesale buyers and sellers. Unlike certain other
regional power markets, the ERCOT market is not a centrally dispatched power
pool, and the ERCOT ISO does not procure energy on behalf of its members other
than to maintain the reliable operations of the transmission system. Members who
sell and purchase
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power are
responsible for contracting sales and purchases of power bilaterally. The ERCOT
ISO also serves as agent for procuring ancillary services for those members who
elect not to provide their own ancillary services.
CenterPoint
Houston’s electric transmission business, along with those of other owners of
transmission facilities in Texas, supports the operation of the ERCOT ISO. The
transmission business has planning, design, construction, operation and
maintenance responsibility for the portion of the transmission grid and for the
load-serving substations it owns, primarily within its certificated area.
CenterPoint Houston participates with the ERCOT ISO and other ERCOT utilities to
plan, design, obtain regulatory approval for and construct new transmission
lines necessary to increase bulk power transfer capability and to remove
existing constraints on the ERCOT transmission grid.
Recovery
of True-Up Balance
The Texas
electric restructuring law substantially revised the regulatory structure
governing electric utilities in order to allow retail competition for electric
customers beginning in January 2002. The Texas electric restructuring law
required the Texas Utility Commission to conduct a "true-up" proceeding to
determine CenterPoint Houston’s stranded costs and certain other costs resulting
from the transition to a competitive retail electric market and to provide for
its recovery of those costs.
In March
2004, CenterPoint Houston filed its true-up application with the Texas Utility
Commission, requesting recovery of $3.7 billion, excluding interest, as
allowed under the Texas electric restructuring law. In December 2004, the Texas
Utility Commission issued its final order (True-Up Order) allowing CenterPoint
Houston to recover a true-up balance of approximately $2.3 billion, which
included interest through August 31, 2004, and provided for adjustment of
the amount to be recovered to include interest on the balance until recovery,
along with the principal portion of additional excess mitigation credits (EMCs)
returned to customers after August 31, 2004 and certain other
adjustments.
CenterPoint
Houston and other parties filed appeals of the True-Up Order to a district court
in Travis County, Texas. In August 2005, that court issued its judgment on the
various appeals. In its judgment, the district court:
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reversed
the Texas Utility Commission’s ruling that had denied recovery of a
portion of the capacity auction true-up
amounts;
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reversed
the Texas Utility Commission’s ruling that precluded CenterPoint Houston
from recovering the interest component of the EMCs paid to REPs;
and
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affirmed
the True-Up Order in all other
respects.
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The
district court’s decision would have had the effect of restoring approximately
$650 million, plus interest, of the $1.7 billion the Texas Utility
Commission had disallowed from CenterPoint Houston’s initial
request.
CenterPoint
Houston and other parties appealed the district court’s judgment to the Texas
Third Court of Appeals, which issued its decision in December 2007. In its
decision, the court of appeals:
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reversed
the district court’s judgment to the extent it restored the capacity
auction true-up amounts;
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reversed
the district court’s judgment to the extent it upheld the Texas Utility
Commission’s decision to allow CenterPoint Houston to recover EMCs paid to
RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant
Resources, Inc.);
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ordered
that the tax normalization issue described below be remanded to the Texas
Utility Commission as requested by the Texas Utility Commission;
and
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affirmed
the district court’s judgment in all other
respects.
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In April
2008, the court of appeals denied all motions for rehearing and reissued
substantially the same opinion as it had rendered in December 2007.
In June
2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the
court of appeals decision. In its petition, CenterPoint Houston seeks reversal
of the parts of the court of appeals decision that (i) denied recovery of EMCs
paid to RRI, (ii) denied recovery of the capacity auction true-up amounts
allowed by the district court, (iii) affirmed the Texas Utility Commission’s
rulings that denied recovery of approximately $378 million related to
depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit
CenterPoint Houston to utilize the partial stock valuation methodology for
determining the market value of its former generation assets. Two other
petitions for review were filed with the Texas Supreme Court by other parties to
the appeal. In those petitions parties contend that (i) the Texas Utility
Commission was without authority to fashion the methodology it used for valuing
the former generation assets after it had determined that CenterPoint Houston
could not use the partial stock valuation method, (ii) in fashioning the method
it used for valuing the former generating assets, the Texas Utility Commission
deprived parties of their due process rights and an opportunity to be heard,
(iii) the net book value of the generating assets should have been adjusted
downward due to the impact of a purchase option that had been granted to RRI,
(iv) CenterPoint Houston should not have been permitted to recover construction
work in progress balances without proving those amounts in the manner required
by law and (v) the Texas Utility Commission was without authority to award
interest on the capacity auction true up award.
In June
2009, the Texas Supreme Court granted the petitions for review of the court of
appeals decision. Oral argument before the court was held in October
2009. Although we and CenterPoint Houston believe that CenterPoint
Houston’s true-up request is consistent with applicable statutes and regulations
and, accordingly, that it is reasonably possible that it will be successful in
its appeal to the Texas Supreme Court, we can provide no assurance as to the
ultimate court rulings on the issues to be considered in the appeal or with
respect to the ultimate decision by the Texas Utility Commission on the tax
normalization issue described below.
To
reflect the impact of the True-Up Order, in 2004 and 2005, we recorded a net
after-tax extraordinary loss of $947 million. No amounts related to the
district court’s judgment or the decision of the court of appeals have been
recorded in our consolidated financial statements. However, if the court of
appeals decision is not reversed or modified as a result of further review by
the Texas Supreme Court, we anticipate that we would be required to record an
additional loss to reflect the court of appeals decision. The amount of that
loss would depend on several factors, including ultimate resolution of the tax
normalization issue described below and the calculation of interest on any
amounts CenterPoint Houston ultimately is authorized to recover or is required
to refund beyond the amounts recorded based on the True-Up Order, but could
range from $180 million to $410 million (pre-tax) plus interest
subsequent to December 31, 2009.
In the
True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s
stranded cost recovery by approximately $146 million, which was included in
the extraordinary loss discussed above, for the present value of certain
deferred tax benefits associated with its former electric generation assets. We
believe that the Texas Utility Commission based its order on proposed
regulations issued by the Internal Revenue Service (IRS) in March 2003 that
would have allowed utilities owning assets that were deregulated before
March 4, 2003 to make a retroactive election to pass the benefits of
Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal
Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew
those proposed normalization regulations and, in March 2008, adopted final
regulations that would not permit utilities like CenterPoint Houston to pass the
tax benefits back to customers without creating normalization violations. In
addition, we received a Private Letter Ruling (PLR) from the IRS in August 2007,
prior to adoption of the final regulations, that confirmed that the Texas
Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery
by $146 million for ADITC and EDFIT would cause normalization violations
with respect to the ADITC and EDFIT.
If the
Texas Utility Commission’s order relating to the ADITC reduction is not reversed
or otherwise modified on remand so as to eliminate the normalization violation,
the IRS could require us to pay an amount equal to CenterPoint Houston’s
unamortized ADITC balance as of the date that the normalization violation is
deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the
ability to elect accelerated tax depreciation benefits beginning in the taxable
year that the normalization violation is deemed to have occurred. Such
treatment, if required by the IRS, could have a material adverse impact on our
results of operations, financial condition and cash flows in addition to any
potential loss resulting from final resolution of the True-Up Order. In its
opinion, the court of appeals ordered that this issue be remanded to the Texas
Utility Commission, as that commission requested. No party has challenged that
order by the court of appeals although the Texas Supreme Court has the authority
to
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consider
all aspects of the rulings above, not just those challenged specifically by the
appellants. We and CenterPoint Houston will continue to pursue a favorable
resolution of this issue through the appellate and administrative process.
Although the Texas Utility Commission has not previously required a company
subject to its jurisdiction to take action that would result in a normalization
violation, no prediction can be made as to the ultimate action the Texas Utility
Commission may take on this issue on remand.
The Texas
electric restructuring law allowed the amounts awarded to CenterPoint Houston in
the Texas Utility Commission’s True-Up Order to be recovered either through
securitization or through implementation of a CTC or both. Pursuant to a
financing order issued by the Texas Utility Commission in March 2005 and
affirmed by a Travis County district court, in December 2005, a new special
purpose subsidiary of CenterPoint Houston issued $1.85 billion in
transition bonds with interest rates ranging from 4.84% to 5.30% and final
maturity dates ranging from February 2011 to August 2020. Through issuance of
the transition bonds, CenterPoint Houston recovered approximately
$1.7 billion of the true-up balance determined in the True-Up Order plus
interest through the date on which the bonds were issued.
In July
2005, CenterPoint Houston received an order from the Texas Utility Commission
allowing it to implement a CTC designed to collect the remaining
$596 million from the True-Up Order over 14 years plus interest at an
annual rate of 11.075% (CTC Order). The CTC Order authorized CenterPoint Houston
to impose a charge on REPs to recover the portion of the true-up balance not
recovered through a financing order. The CTC Order also allowed CenterPoint
Houston to collect approximately $24 million of rate case expenses over
three years without a return through a separate tariff rider (Rider RCE).
CenterPoint Houston implemented the CTC and Rider RCE effective
September 13, 2005 and began recovering approximately $620 million.
The return on the CTC portion of the true-up balance was included in CenterPoint
Houston’s tariff-based revenues beginning September 13, 2005. Effective
August 1, 2006, the interest rate on the unrecovered balance of the CTC was
reduced from 11.075% to 8.06% pursuant to a revised rule adopted by the Texas
Utility Commission in June 2006. Recovery of rate case expenses under Rider RCE
was completed in September 2008.
Certain
parties appealed the CTC Order to a district court in Travis County. In May
2006, the district court issued a judgment reversing the CTC Order in three
respects. First, the court ruled that the Texas Utility Commission had
improperly relied on provisions of its rule dealing with the interest rate
applicable to CTC amounts. The district court reached that conclusion based on
its belief that the Texas Supreme Court had previously invalidated that entire
section of the rule. The 11.075% interest rate in question was applicable from
the implementation of the CTC Order on September 13, 2005 until
August 1, 2006, the effective date of the implementation of a new CTC in
compliance with the revised rule discussed above. Second, the district court
reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston
to recover through Rider RCE the costs (approximately $5 million) for a
panel appointed by the Texas Utility Commission in connection with the valuation
of electric generation assets. Finally, the district court accepted the
contention of one party that the CTC should not be allocated to retail customers
that have switched to new on-site generation. The Texas Utility Commission and
CenterPoint Houston appealed the district court’s judgment to the Texas
Third Court of Appeals, and in July 2008, the court of appeals reversed the
district court’s judgment in all respects and affirmed the Texas Utility
Commission’s order. Two parties appealed the court of appeals decision to the
Texas Supreme Court, which heard oral argument in October 2009. The ultimate
outcome of this matter cannot be predicted at this time. However, we do not
expect the disposition of this matter to have a material adverse effect on our
or CenterPoint Houston’s financial condition, results of operations or cash
flows.
During
the 2007 legislative session, the Texas legislature amended statutes prescribing
the types of true-up balances that can be securitized by utilities and
authorized the issuance of transition bonds to recover the balance of the CTC.
In June 2007, CenterPoint Houston filed a request with the Texas Utility
Commission for a financing order that would allow the securitization of the
remaining balance of the CTC, adjusted to refund certain unspent environmental
retrofit costs and to recover the amount of the final fuel reconciliation
settlement. CenterPoint Houston reached substantial agreement with other parties
to this proceeding, and a financing order was approved by the Texas Utility
Commission in September 2007. In February 2008, pursuant to the financing order,
a new special purpose subsidiary of CenterPoint Houston issued approximately
$488 million of transition bonds in two tranches with interest rates of
4.192% and 5.234% and final maturity dates of February 2020 and February 2023,
respectively. Contemporaneously with the issuance of those bonds, the CTC was
terminated and a transition charge
5
was
implemented. During the years ended December 31, 2007 and 2008, CenterPoint
Houston recognized approximately $42 million and $5 million,
respectively, in operating income from the CTC.
As of
December 31, 2009, we have not recognized an allowed equity return of
$193 million on CenterPoint Houston’s true-up balance because such return
will be recognized as it is recovered in rates. Additionally, during the years
ended December 31, 2007, 2008 and 2009, CenterPoint Houston recognized
approximately $14 million, $13 million and $13 million,
respectively, of the allowed equity return not previously
recognized.
Hurricane
Ike
CenterPoint
Houston’s electric delivery system suffered substantial damage as a result of
Hurricane Ike, which struck the upper Texas coast in
September 2008.
As is
common with electric utilities serving coastal regions, the poles, towers,
wires, street lights and pole mounted equipment that comprise CenterPoint
Houston’s transmission and distribution system are not covered by property
insurance, but office buildings and warehouses and their contents and
substations are covered by insurance that provides for a maximum deductible of
$10 million. Current estimates are that total losses to property covered by
this insurance were approximately $30 million.
CenterPoint
Houston deferred the uninsured system restoration costs as management believed
it was probable that such costs would be recovered through the regulatory
process. As a result, system restoration costs did not affect CenterPoint
Energy’s or CenterPoint Houston’s reported operating income for 2008 or
2009.
Legislation
enacted by the Texas Legislature in April 2009 authorized the Texas Utility
Commission to conduct proceedings to determine the amount of system restoration
costs and related costs associated with hurricanes or other major storms that
utilities are entitled to recover, and to issue financing orders that would
permit a utility like CenterPoint Houston to recover the distribution portion of
those costs and related carrying costs through the issuance of non-recourse
system restoration bonds similar to the securitization bonds issued
previously. The legislation also allowed such a utility to recover,
or defer for future recovery, the transmission portion of its system restoration
costs through the existing mechanisms established to recover transmission
costs.
Pursuant
to such legislation, CenterPoint Houston filed with the Texas Utility Commission
an application for review and approval for recovery of approximately
$678 million, including approximately $608 million in system
restoration costs identified as of the end of February 2009, plus
$2 million in regulatory expenses, $13 million in certain debt
issuance costs and $55 million in incurred and projected carrying costs
calculated through August 2009. In July 2009, CenterPoint Houston announced
a settlement agreement with the parties to the proceeding. Under that
settlement agreement, CenterPoint Houston was entitled to recover a total of
$663 million in costs relating to Hurricane Ike, along with carrying costs from September 1,
2009 until system restoration bonds were issued. The Texas Utility Commission
issued an order in August 2009 approving CenterPoint Houston’s application and
the settlement agreement and authorizing recovery of $663 million, of which
$643 million was attributable to distribution service and eligible for
securitization and the remaining $20 million was attributable to
transmission service and eligible for recovery through the existing mechanisms
established to recover transmission costs.
In July
2009, CenterPoint Houston filed with the Texas Utility Commission its
application for a financing order to recover the portion of approved costs
related to distribution service through the issuance of system restoration
bonds. In August 2009, the Texas Utility Commission issued a
financing order allowing CenterPoint Houston to securitize $643 million in
distribution service costs plus carrying charges from September 1, 2009
through the date the system restoration bonds were issued, as well as certain
up-front qualified costs capped at approximately $6 million. In
November 2009, CenterPoint Houston issued approximately $665 million of
system restoration bonds through its CenterPoint Energy Restoration Bond
Company, LLC subsidiary with interest rates of 1.833% to 4.243% and final
maturity dates ranging from February 2016 to August 2023. The bonds
will be repaid over time through a charge imposed on customers.
In
accordance with the financing order, CenterPoint Houston also placed a separate
customer credit in effect when the storm restoration bonds were
issued. That credit (ADFIT Credit) is applied to customers’ bills
while the bonds are outstanding to reflect the benefit of accumulated deferred
federal income taxes (ADFIT) associated with
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the storm
restoration costs (including a carrying charge of 11.075%). The beginning
balance of the ADFIT related to storm restoration costs was approximately
$207 million and will decline over the life of the system restoration bonds
as taxes are paid on the system restoration tariffs. The ADFIT Credit will
reduce operating income in 2010 by approximately
$24 million.
In
accordance with the orders discussed above, as of December 31, 2009, CenterPoint
Houston has recorded $651 million associated with distribution-related
storm restoration costs as a net regulatory asset and $20 million
associated with transmission-related storm restoration costs, of which
$18 million is recorded in property, plant and equipment and
$2 million of related carrying costs is recorded in regulatory
assets. These amounts reflect carrying costs of $60 million related
to distribution and $2 million related to transmission through December 31,
2009, based on the 11.075% cost of capital approved by the Texas Utility
Commission. The carrying costs have been bifurcated into two components:
(i) return of borrowing costs and (ii) an allowance for earnings on
shareholders’ investment. During the year ended December 31, 2009, the
component representing a return of borrowing costs of $23 million has been
recognized and is included in other income in our Statements of Consolidated
Income. The component representing an allowance for earnings on
shareholders’ investment of $39 million is being deferred and will be
recognized as it is collected through rates.
Customers
CenterPoint
Houston serves nearly all of the Houston/Galveston metropolitan area.
CenterPoint Houston’s customers consist of approximately 80 REPs, which sell
electricity to over 2 million metered customers in CenterPoint Houston’s
certificated service area, and municipalities, electric cooperatives and other
distribution companies located outside CenterPoint Houston’s certificated
service area. Each REP is licensed by, and must meet minimum creditworthiness
criteria established by, the Texas Utility Commission. Sales to REPs that are
subsidiaries of NRG Retail LLC (formerly subsidiaries of RRI) represented
approximately 51%, 48% and 44% of CenterPoint Houston’s transmission and
distribution revenues in 2007, 2008 and 2009, respectively. CenterPoint
Houston’s billed receivables balance from REPs as of December 31, 2009 was
$139 million. Approximately 41% of this amount was owed by subsidiaries of
NRG Retail LLC. CenterPoint Houston does not have long-term contracts with any
of its customers. It operates on a continuous billing cycle, with meter readings
being conducted and invoices being distributed to REPs each business
day.
Advanced
Metering System and Distribution Automation (Intelligent Grid)
In
December 2008, CenterPoint Houston received approval from the Texas Utility
Commission to deploy an advanced metering system (AMS) across its service
territory over the next five years. CenterPoint Houston began installing
advanced meters in March 2009. This innovative technology should encourage
greater energy conservation by giving Houston-area electric consumers the
ability to better monitor and manage their electric use and its cost in near
real time. CenterPoint Houston will recover the cost for the AMS through a
monthly surcharge to all REPs over 12 years. The surcharge for each
residential consumer for the first 24 months, which began in February 2009, is
$3.24 per month; thereafter, the surcharge is scheduled to be reduced to $3.05
per month. These amounts are subject to upward or downward adjustment in
future proceedings to reflect actual costs incurred and to address required
changes in scope. CenterPoint Houston projects capital expenditures of
approximately $640 million for the installation of the advanced meters and
corresponding communication and data management systems over the five-year
deployment period.
CenterPoint
Houston is also pursuing deployment of an electric distribution grid automation
strategy that involves the implementation of an "Intelligent Grid" which would
make use of CenterPoint Houston’s facilities to provide on-demand data and
information about the status of facilities on its system. Although this
technology is still in the developmental stage, CenterPoint Houston believes it
has the potential to provide a significant improvement in grid planning,
operations, maintenance and customer service for the CenterPoint Houston
distribution system. These improvements are expected to contribute to fewer and
shorter outages, better customer service, improved operations costs, improved
security and more effective use of our workforce. We expect to include the costs
of the deployment in future rate proceedings before the Texas Utility
Commission.
In
October 2009, the U.S. Department of Energy (DOE) notified CenterPoint Houston
that it had been selected for a $200 million grant for its advanced
metering system and intelligent grid projects. The award is contingent on
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successful
completion of negotiations with the DOE. CenterPoint Houston applied for the
grant in August 2009 to obtain $150 million in funding to accelerate
completion of CenterPoint Houston’s current deployment of advanced meters by
2012, instead of 2014 as originally scheduled. In addition, the grant
request included $50 million to begin building the intelligent grid.
At this time, CenterPoint Houston cannot predict the schedule for completion of
negotiations with the DOE or the final terms of any grant it ultimately
receives.
Competition
There are
no other electric transmission and distribution utilities in CenterPoint
Houston’s service area. In order for another provider of transmission and
distribution services to provide such services in CenterPoint Houston’s
territory, it would be required to obtain a certificate of convenience and
necessity from the Texas Utility Commission and, depending on the location of
the facilities, may also be required to obtain franchises from one or more
municipalities. We know of no other party intending to enter this business in
CenterPoint Houston’s service area at this time.
Seasonality
A
significant portion of CenterPoint Houston’s revenues is derived from rates that
it collects from each REP based on the amount of electricity it delivers on
behalf of such REP. Thus, CenterPoint Houston’s revenues and results of
operations are subject to seasonality, weather conditions and other changes in
electricity usage, with revenues being higher during the warmer
months.
Properties
All of
CenterPoint Houston’s properties are located in Texas. Its properties consist
primarily of high voltage electric transmission lines and poles, distribution
lines, substations, service wires and meters. Most of CenterPoint Houston’s
transmission and distribution lines have been constructed over lands of others
pursuant to easements or along public highways and streets as permitted by
law.
All real
and tangible properties of CenterPoint Houston, subject to certain exclusions,
are currently subject to:
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the
lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1,
1944, as supplemented; and
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the
lien of a General Mortgage (the General Mortgage) dated October 10,
2002, as supplemented, which is junior to the lien of the
Mortgage.
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As of
December 31, 2009, CenterPoint Houston had outstanding approximately
$2.5 billion aggregate principal amount of general mortgage bonds under the
General Mortgage, including approximately $527 million held in trust to
secure pollution control bonds for which CenterPoint Energy is obligated and
approximately $229 million held in trust to secure pollution control bonds
for which CenterPoint Houston is obligated. Additionally, CenterPoint Houston
had outstanding approximately $253 million aggregate principal amount of
first mortgage bonds under the Mortgage, including approximately
$151 million held in trust to secure certain pollution control bonds for
which CenterPoint Energy is obligated. CenterPoint Houston may issue additional
general mortgage bonds on the basis of retired bonds, 70% of property additions
or cash deposited with the trustee. Approximately $2.1 billion of
additional first mortgage bonds and general mortgage bonds in the aggregate
could be issued on the basis of retired bonds and 70% of property additions as
of December 31, 2009. However, CenterPoint Houston has contractually agreed
that it will not issue additional first mortgage bonds, subject to certain
exceptions.
Electric Lines -
Overhead. As of December 31, 2009, CenterPoint Houston
owned 27,726 pole miles of overhead distribution lines and 3,729 circuit miles
of overhead transmission lines, including 423 circuit miles operated at 69,000
volts, 2,090 circuit miles operated at 138,000 volts and 1,216 circuit miles
operated at 345,000 volts.
Electric Lines -
Underground. As of December 31, 2009, CenterPoint Houston
owned 20,080 circuit miles of underground distribution lines and 26 circuit
miles of underground transmission lines, including 2 circuit miles operated at
69,000 volts and 24 circuit miles operated at 138,000 volts.
Substations. As of
December 31, 2009, CenterPoint Houston owned 230 major substation sites
having a total installed rated transformer capacity of 51,557 megavolt
amperes.
Service
Centers. CenterPoint Houston operates 14 regional service
centers located on a total of 291 acres of land. These service centers
consist of office buildings, warehouses and repair facilities that are used in
the business of transmitting and distributing electricity.
Franchises
CenterPoint
Houston holds non-exclusive franchises from the incorporated municipalities in
its service territory. In exchange for the payment of fees, these franchises
give CenterPoint Houston the right to use the streets and public rights-of way
of these municipalities to construct, operate and maintain its transmission and
distribution system and to use that system to conduct its electric delivery
business and for other purposes that the franchises permit. The terms of the
franchises, with various expiration dates, typically range from 30 to
50 years.
Natural
Gas Distribution
CERC
Corp.’s natural gas distribution business (Gas Operations) engages in regulated
intrastate natural gas sales to, and natural gas transportation for,
approximately 3.2 million residential, commercial and industrial customers
in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The largest
metropolitan areas served in each state by Gas Operations are Houston, Texas;
Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi,
Mississippi; and Lawton, Oklahoma. In 2009, approximately 43% of Gas Operations’
total throughput was to residential customers and approximately 57% was to
commercial and industrial customers.
Gas
Operations also provides unregulated services consisting of heating, ventilating
and air conditioning (HVAC) equipment and appliance repair, and sales of HVAC,
hearth and water heating equipment in Minnesota.
The
demand for intrastate natural gas sales to, and natural gas transportation for,
residential, commercial and industrial customers is seasonal. In 2009,
approximately 70% of the total throughput of Gas Operations’ business occurred
in the first and fourth quarters. These patterns reflect the higher demand for
natural gas for heating purposes during those periods.
Gas
Operations also suffered some damage to its system in Houston, Texas and in
other portions of its service territory across Texas and Louisiana as a result
of Hurricane Ike. As of December 31, 2009, Gas Operations has deferred
approximately $3 million of costs related to Hurricane Ike for recovery as
part of future natural gas distribution rate proceedings.
Supply and
Transportation. In 2009, Gas Operations purchased virtually
all of its natural gas supply pursuant to contracts with remaining terms varying
from a few months to four years. Major suppliers in 2009 included BP Canada
Energy Marketing Corp. (20.5% of supply volumes), Coral Energy Resources (8.3%),
Tenaska Marketing Ventures (8.2%), Kinder Morgan (8.0%), ConocoPhillips Company
(7.4%), and Cargill, Inc. (5.7%). Numerous other suppliers provided the
remaining 41.9% of Gas Operations’ natural gas supply requirements. Gas
Operations transports its natural gas supplies through various intrastate and
interstate pipelines, including those owned by our other subsidiaries, under
contracts with remaining terms, including extensions, varying from one to
fifteen years. Gas Operations anticipates that these gas supply and
transportation contracts will be renewed or replaced prior to their
expiration.
We
actively engage in commodity price stabilization pursuant to annual gas supply
plans presented to and/or filed with each of our state regulatory authorities.
These price stabilization activities include use of storage gas, contractually
establishing fixed prices with our physical gas suppliers and utilizing
financial derivative instruments to achieve a variety of pricing structures
(e.g., fixed price, costless collars and caps). Our gas supply plans generally
call for 25-50% of winter supplies to be hedged in some fashion.
Generally,
the regulations of the states in which Gas Operations operates allow it to pass
through changes in the cost of natural gas, including gains and losses on
financial derivatives associated with the index-priced physical supply, to its
customers under purchased gas adjustment provisions in its tariffs. Depending
upon the jurisdiction,
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the
purchased gas adjustment factors are updated periodically, ranging from monthly
to semi-annually, using estimated gas costs. The changes in the cost of gas
billed to customers are subject to review by the applicable regulatory
bodies.
Gas
Operations uses various third-party storage services or owned natural gas
storage facilities to meet peak-day requirements and to manage the daily changes
in demand due to changes in weather and may also supplement contracted supplies
and storage from time to time with stored liquefied natural gas and propane-air
plant production.
Gas
Operations owns and operates an underground natural gas storage facility with a
capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of
2.0 Bcf available for use during a normal heating season and a maximum
daily withdrawal rate of 50 million cubic feet (MMcf). It also owns nine
propane-air plants with a total production rate of 200 Dekatherms (DTH) per
day and on-site storage facilities for 12 million gallons of propane
(1.0 Bcf natural gas equivalent). It owns a liquefied natural gas plant
facility with a 12 million-gallon liquefied natural gas storage tank
(1.0 Bcf natural gas equivalent) and a production rate of 72 DTH per
day.
On an
ongoing basis, Gas Operations enters into contracts to provide sufficient
supplies and pipeline capacity to meet its customer requirements. However, it is
possible for limited service disruptions to occur from time to time due to
weather conditions, transportation constraints and other events. As a result of
these factors, supplies of natural gas may become unavailable from time to time,
or prices may increase rapidly in response to temporary supply constraints or
other factors.
Gas
Operations has entered into various asset management agreements associated with
its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma
and Texas. Generally, these asset management agreements are contracts
between Gas Operations and an asset manager that are intended to transfer the
working capital obligation and maximize the utilization of the assets. In these
agreements, Gas Operations agreed to release transportation and storage capacity
to other parties to manage gas storage, supply and delivery arrangements for Gas
Operations and to use the released capacity for other purposes when it is not
needed for Gas Operations. Gas Operations is compensated by the asset
manager through payments made over the life of the agreements based in part on
the results of the asset optimization. Gas Operations has received
approval from the state regulatory commissions in Arkansas, Louisiana,
Mississippi and Oklahoma to retain a share of the asset management agreement
proceeds, although the percentage of payments to be retained by Gas Operations
varies based on the jurisdiction, with the majority of the payments to benefit
customers. The agreements have varying terms, the longest of which expires in
2016.
Assets
As of
December 31, 2009, Gas Operations owned approximately 70,700 linear miles
of natural gas distribution mains, varying in size from one-half inch to
24 inches in diameter. Generally, in each of the cities, towns and rural
areas served by Gas Operations, it owns the underground gas mains and service
lines, metering and regulating equipment located on customers’ premises and the
district regulating equipment necessary for pressure maintenance. With a few
exceptions, the measuring stations at which Gas Operations receives gas are
owned, operated and maintained by others, and its distribution facilities begin
at the outlet of the measuring equipment. These facilities, including odorizing
equipment, are usually located on the land owned by suppliers.
Competition
Gas
Operations competes primarily with alternate energy sources such as electricity
and other fuel sources. In some areas, intrastate pipelines, other gas
distributors and marketers also compete directly for gas sales to end-users. In
addition, as a result of federal regulations affecting interstate pipelines,
natural gas marketers operating on these pipelines may be able to bypass Gas
Operations’ facilities and market and sell and/or transport natural gas directly
to commercial and industrial customers.
Competitive
Natural Gas Sales and Services
CERC
offers variable and fixed-priced physical natural gas supplies primarily to
commercial and industrial customers and electric and gas utilities through
CenterPoint Energy Services, Inc. (CES) and its subsidiary, CenterPoint Energy
Intrastate Pipelines, LLC (CEIP).
In 2009,
CES marketed approximately 504 Bcf of natural gas, related energy services
and transportation to approximately 11,100 customers (including approximately
3 Bcf to affiliates). CES customers vary in size from small commercial
customers to large utility companies in the central and eastern regions of the
United States. The business has three operational divisions: wholesale, retail
and intrastate pipelines, which are further described below.
Wholesale
Division. CES offers a portfolio of physical delivery services
and financial products designed to meet wholesale customers’ supply and price
risk management needs. These customers are served directly through interconnects
with various interstate and intrastate pipeline companies, and include gas
utilities, large industrial customers and electric generation customers. This
division includes the supply function for the procurement of natural gas and the
management and optimization of transportation and storage assets for
CES.
Retail
Division. CES offers a variety of natural gas management
services to smaller commercial and industrial customers, municipalities,
educational institutions and hospitals, whose facilities are typically located
downstream of natural gas distribution utility city gate stations. These
services include load forecasting, supply acquisition, daily swing volume
management, invoice consolidation, storage asset management, firm and
interruptible transportation administration and forward price management. CES
manages transportation contracts and energy supply for retail customers in 18
states.
Intrastate Pipeline
Division. CEIP provides transportation services to shippers
and end-users and contracts out approximately 2.3 Bcf of storage at its
Pierce Junction facility in Texas.
CES
currently transports natural gas on over 41 interstate and intrastate pipelines
within states located throughout the central and eastern United States. CES
maintains a portfolio of natural gas supply contracts and firm transportation
and storage agreements to meet the natural gas requirements of its customers.
CES aggregates supply from various producing regions and offers contracts to buy
natural gas with terms ranging from one month to over five years. In addition,
CES actively participates in the spot natural gas markets in an effort to
balance daily and monthly purchases and sales obligations. Natural gas supply
and transportation capabilities are leveraged through contracts for ancillary
services including physical storage and other balancing
arrangements.
As
described above, CES offers its customers a variety of load following services.
In providing these services, CES uses its customers’ purchase commitments to
forecast and arrange its own supply purchases, storage and transportation
services to serve customers’ natural gas requirements. As a result of the
variance between this forecast activity and the actual monthly activity, CES
will either have too much supply or too little supply relative to its customers’
purchase commitments. These supply imbalances arise each month as customers’
natural gas requirements are scheduled and corresponding natural gas supplies
are nominated by CES for delivery to those customers. CES’ processes and risk
control environment are designed to measure and value imbalances on a real-time
basis to ensure that CES’ exposure to commodity price risk is kept to a minimum.
The value assigned to these imbalances is calculated daily and is known as the
aggregate Value at Risk (VaR). In 2009, CES’ VaR averaged $0.6 million with
a high of $1.6 million.
Our risk
control policy, governed by our Risk Oversight Committee, defines authorized and
prohibited trading instruments and trading limits. CES is a physical marketer of
natural gas and uses a variety of tools, including pipeline and storage
capacity, financial instruments and physical commodity purchase contracts to
support its sales. The CES business optimizes its use of these various tools to
minimize its supply costs and does not engage in proprietary or speculative
commodity trading. The VaR limits, $4 million maximum, within which CES
operates are consistent with its operational objective of matching its aggregate
sales obligations (including the swing associated with load following services)
with its supply portfolio in a manner that minimizes its total cost of
supply.
Assets
CEIP owns
and operates approximately 230 miles of intrastate pipeline in Louisiana
and Texas and holds storage facilities of approximately 2.3 Bcf in Texas
under long-term leases. In addition, CES leases transportation capacity of
approximately 0.8 Bcf per day on various interstate and intrastate
pipelines and approximately 12.5 Bcf of storage to service its customer
base.
Competition
CES
competes with regional and national wholesale and retail gas marketers including
the marketing divisions of natural gas producers and utilities. In addition, CES
competes with intrastate pipelines for customers and services in its market
areas.
Interstate
Pipelines
CERC’s
pipelines business operates interstate natural gas pipelines with gas
transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri,
Oklahoma and Texas. CERC’s interstate pipeline operations are primarily
conducted by two wholly owned subsidiaries that provide gas transportation and
storage services primarily to industrial customers and local distribution
companies:
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CenterPoint
Energy Gas Transmission Company (CEGT) is an interstate pipeline that
provides natural gas transportation, natural gas storage and pipeline
services to customers principally in Arkansas, Louisiana, Oklahoma and
Texas; and
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CenterPoint
Energy-Mississippi River Transmission Corporation (MRT) is an interstate
pipeline that provides natural gas transportation, natural gas storage and
pipeline services to customers principally in Arkansas and
Missouri.
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The rates
charged by CEGT and MRT for interstate transportation and storage services are
regulated by the FERC. CERC's interstate pipelines business operations may be
affected by changes in the demand for natural gas, the available supply and
relative price of natural gas in the Mid-continent and Gulf Coast natural gas
supply regions and general economic conditions.
In 2009,
approximately 16% of CEGT and MRT’s total operating revenue was attributable to
services provided to Gas Operations, an affiliate, and approximately 7% was
attributable to services provided to Laclede Gas Company (Laclede), an
unaffiliated distribution company, that provides natural gas utility service to
the greater St. Louis metropolitan area in Illinois and Missouri. Services
to Gas Operations and Laclede are provided under several long-term firm storage
and transportation agreements. The primary term of MRT’s firm
transportation and storage contracts with Laclede will expire in
2013. The primary term of CEGT’s agreements for firm transportation,
"no notice" transportation service and storage services in certain of Gas
Operations’ service areas (Arkansas, Louisiana, Oklahoma and Texas) will expire
in 2012.
Carthage to Perryville. In
February 2010, CEGT completed the expansion of the capacity of its Carthage to
Perryville pipeline to approximately 1.9 Bcf per day. The expansion
includes new compressor units at two of CEGT’s existing stations.
Southeast Supply Header, LLC.
CenterPoint Southeastern Pipelines Holding, LLC, a wholly-owned
subsidiary of CERC, owns a 50% interest in Southeast Supply Header, LLC (SESH).
SESH owns a 1.0 Bcf per day, 274-mile interstate pipeline that runs from the
Perryville Hub in Louisiana to Coden, Alabama. The pipeline was placed into
service in September 2008. The rates charged by SESH for interstate
transportation services are regulated by the FERC. A wholly-owned, indirect
subsidiary of Spectra Energy Corp. owns the remaining 50% interest in
SESH.
Assets
CERC's
interstate pipelines business currently owns and operates approximately
8,000 miles of natural gas transmission lines primarily located in
Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. CERC's
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interstate
pipeline business also owns and operates six natural gas storage fields with a
combined daily deliverability of approximately 1.2 Bcf and a combined
working gas capacity of approximately 59 Bcf. CERC's interstate pipeline
business also owns a 10% interest in the Bistineau storage facility located in
Bienville Parish, Louisiana, with the remaining interest owned and operated by
Gulf South Pipeline Company, LP. CERC's interstate pipeline business' storage
capacity in the Bistineau facility is 8 Bcf of working gas with
100 MMcf per day of deliverability. Most storage operations are in north
Louisiana and Oklahoma.
Competition
CERC's
interstate pipelines business competes with other interstate and intrastate
pipelines in the transportation and storage of natural gas. The principal
elements of competition among pipelines are rates, terms of service, and
flexibility and reliability of service. CERC's interstate pipelines business
competes indirectly with other forms of energy, including electricity, coal and
fuel oils. The primary competitive factor is price, but recently, environmental
considerations have grown in importance when consumers consider other forms of
energy. Changes in the availability of energy and pipeline capacity, the level
of business activity, conservation and governmental regulations, the capability
to convert to alternative fuels, and other factors, including weather, affect
the demand for natural gas in areas we serve and the level of competition for
transportation and storage services.
Field
Services
CERC’s
field services business operates gas gathering, treating and processing
facilities and also provides operating and technical services and remote data
monitoring and communication services.
CERC’s
field services operations are conducted by a wholly owned subsidiary,
CenterPoint Energy Field Services, Inc. (CEFS). CEFS provides natural gas
gathering and processing services for certain natural gas fields in the
Mid-continent region of the United States that interconnect with CEGT’s and
MRT’s pipelines, as well as other interstate and intrastate pipelines. CEFS
gathers approximately 1.4 Bcf per day of natural gas and, either directly
or through its 50% interest in a joint venture, processes in excess of
250 MMcf per day of natural gas along its gathering system. CEFS, through
its ServiceStar operating division, provides remote data monitoring and
communications services to affiliates and third parties.
CERC's
field services business operations may be affected by changes in the demand for
natural gas and natural gas liquids (NGLs), the available supply and relative
price of natural gas and NGLs in the Mid-continent and Gulf Coast natural gas
supply regions and general economic conditions.
Long-Term Gas Gathering and Treating
Agreements. In September 2009, CEFS entered into long-term agreements
with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an
indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide
gathering and treating services for their natural gas production from certain
Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired
jointly-owned gathering facilities from EnCana and Shell in De Soto and Red
River parishes in northwest Louisiana. Each of the agreements
includes acreage dedication and volume commitments for which CEFS has rights to
gather Shell’s and EnCana’s natural gas production from the dedicated
areas.
In
connection with the agreements, CEFS commenced gathering and treating services
utilizing the acquired facilities. CEFS is expanding the acquired facilities in
order to gather and treat up to 700 MMcf per day of natural gas. If EnCana
or Shell elect, CEFS will further expand the facilities in order to gather and
treat additional future volumes. The construction necessary to reach
the contractual capacity of 700 MMcf per day includes more than 200 miles of
gathering lines, nearly 25,500 horsepower of compression and over 800 MMcf per
day of treating capacity.
CEFS
estimates that the purchase of existing facilities and construction to gather
700 MMcf per day will cost up to $325 million. If EnCana and Shell elect
expansion of the project to gather and process additional future volumes of up
to 1 Bcf per day, CEFS estimates that the expansion would cost as much as
an additional $300 million and EnCana and Shell would provide incremental
volume commitments. Funds for construction are being provided from anticipated
cash flows from operations, lines of credit or proceeds from the sale of debt or
equity securities. As of December 31, 2009, approximately
$176 million has been spent on this project, including the purchase of
existing facilities.
Waskom Gas Processing Company.
CenterPoint Energy Gas Processing Company, a wholly-owned, indirect
subsidiary of CERC (CEGP), owns a 50% general partnership interest in Waskom Gas
Processing Company (Waskom). Waskom owns a gas processing plant located in East
Texas. The plant is capable of processing approximately 285 MMcf per day of
natural gas.
Assets
CERC’s
field services business owns and operates approximately 3,700 miles of
gathering lines and processing plants that collect, treat and process natural
gas from approximately 140 separate systems located in major producing fields in
Arkansas, Louisiana, Oklahoma and Texas.
Competition
CERC's
field services business competes with other companies in the natural gas
gathering, treating and processing business. The principal elements of
competition are rates, terms of service and reliability of services. CERC's
field services business competes indirectly with other forms of energy,
including electricity, coal and fuel oils. The primary competitive factor is
price, but recently, environmental considerations have grown in importance when
consumers consider other forms of energy. Changes in the availability of energy
and pipeline capacity, the level of business activity, conservation and
governmental regulations, the capability to convert to alternative fuels, and
other factors, including weather, affect the demand for natural gas in areas we
serve and the level of competition for gathering, treating, and processing
services. In addition, competition among forms of energy is affected by
commodity pricing levels and influences the level of drilling activity and
demand for our gathering operations.
Other
Operations
Our Other
Operations business segment includes office buildings and other real estate used
in our business operations and other corporate operations that support all of
our business operations.
Financial
Information About Segments
For
financial information about our segments, see Note 14 to our consolidated
financial statements, which note is incorporated herein by
reference.
REGULATION
We are
subject to regulation by various federal, state and local governmental agencies,
including the regulations described below.
Federal
Energy Regulatory Commission
The FERC
has jurisdiction under the Natural Gas Act and the Natural Gas Policy Act of
1978, as amended, to regulate the transportation of natural gas in interstate
commerce and natural gas sales for resale in interstate commerce that are not
first sales. The FERC regulates, among other things, the construction of
pipeline and related facilities used in the transportation and storage of
natural gas in interstate commerce, including the extension, expansion or
abandonment of these facilities. The rates charged by interstate pipelines for
interstate transportation and storage services are also regulated by the FERC.
The Energy Policy Act of 2005 (Energy Act) expanded the FERC’s authority to
prohibit market manipulation in connection with FERC-regulated transactions and
gave the FERC additional authority to impose significant civil and criminal
penalties for statutory violations and violations of the FERC’s rules or orders
and also expanded criminal penalties for such violations. Our competitive
natural gas sales and services subsidiary markets natural gas in interstate
commerce pursuant to blanket authority granted by the FERC.
CERC's
natural gas pipeline subsidiaries may periodically file applications with the
FERC for changes in their generally available maximum rates and charges designed
to allow them to recover their costs of providing service to customers (to the
extent allowed by prevailing market conditions), including a reasonable rate of
return. These rates
14
are
normally allowed to become effective after a suspension period and, in some
cases, are subject to refund under applicable law until such time as the FERC
issues an order on the allowable level of rates.
CenterPoint
Houston is not a "public utility" under the Federal Power Act and, therefore, is
not generally regulated by the FERC, although certain of its transactions are
subject to limited FERC jurisdiction. The Energy Act conferred new jurisdiction
and responsibilities on the FERC with respect to ensuring the reliability of
electric transmission service, including transmission facilities owned by
CenterPoint Houston and other utilities within ERCOT. Under this authority, the
FERC has designated the NERC as the Electric Reliability Organization (ERO) to
promulgate standards, under FERC oversight, for all owners, operators and users
of the bulk power system (Electric Entities). The ERO and the FERC have
authority to impose fines and other sanctions on Electric Entities that fail to
comply with approved standards and audit compliance with approved standards. The
FERC has approved the delegation by the NERC of authority for reliability in
ERCOT to the TRE. CenterPoint Houston does not anticipate that the reliability
standards proposed by the NERC and approved by the FERC will have a material
adverse impact on its operations. To the extent that CenterPoint Houston is
required to make additional expenditures to comply with these standards, it is
anticipated that CenterPoint Houston will seek to recover those costs through
the transmission charges that are imposed on all distribution service providers
within ERCOT for electric transmission provided.
Under the
Public Utility Holding Company Act of 2005 (PUHCA 2005), the FERC has authority
to require holding companies and their subsidiaries to maintain certain books
and records and make them available for review by the FERC and state regulatory
authorities in certain circumstances. In December 2005, the FERC issued rules
implementing PUHCA 2005. Pursuant to those rules, in June 2006, we filed with
the FERC the required notification of our status as a public utility holding
company. In October 2006 and December 2009, the FERC adopted additional rules
regarding maintenance of books and records by utility holding companies and
additional reporting and accounting requirements for centralized service
companies that provide non-power goods and services to public utilities, natural
gas companies or both, in the same holding company system.
State
and Local Regulation
Electric
Transmission & Distribution
CenterPoint
Houston conducts its operations pursuant to a certificate of convenience and
necessity issued by the Texas Utility Commission that covers its present service
area and facilities. The Texas Utility Commission and those municipalities that
have retained original jurisdiction have the authority to set the rates and
terms of service provided by CenterPoint Houston under cost of service rate
regulation. CenterPoint Houston holds non-exclusive franchises from the
incorporated municipalities in its service territory. In exchange for payment of
fees, these franchises give CenterPoint Houston the right to use the streets and
public rights-of-way of these municipalities to construct, operate and maintain
its transmission and distribution system and to use that system to conduct its
electric delivery business and for other purposes that the franchises permit.
The terms of the franchises, with various expiration dates, typically range from
30 to 50 years.
CenterPoint
Houston’s distribution rates charged to REPs for residential customers are
primarily based on amounts of energy delivered, whereas distribution rates for a
majority of commercial and industrial customers are primarily based on peak
demand. All REPs in CenterPoint Houston’s service area pay the same rates and
other charges for the same transmission and distribution services. This
regulated delivery charge includes the transmission and distribution rate (which
includes municipal franchise fees), a system benefit fund fee imposed by the
Texas electric restructuring law, a nuclear decommissioning charge associated
with decommissioning the South Texas nuclear generating facility, a surcharge
related to the implementation of AMS and charges associated with securitization
of regulatory assets, stranded costs and restoration costs relating to Hurricane
Ike. Transmission rates charged to other distribution companies are based on
amounts of energy transmitted under "postage stamp" rates that do not vary with
the distance the energy is being transmitted. All distribution companies in
ERCOT pay CenterPoint Houston the same rates and other charges for transmission
services.
Recovery of True-Up
Balance. For a discussion of CenterPoint Houston’s true-up
proceedings, see "- Our Business - Electric Transmission & Distribution -
Recovery of True-Up Balance" above.
Rate Proceedings. In May
2009, CenterPoint Houston filed an application at the Texas Utility Commission
seeking approval of certain estimated 2010 energy efficiency program costs, an
energy efficiency performance bonus for 2008 programs and carrying costs,
totaling approximately $10 million. The application sought to begin
recovery of these costs through a surcharge effective July 1, 2010. In October
2009, the Texas Utility Commission issued its order approving recovery of the
2010 energy efficiency program costs and a partial performance bonus, plus
carrying costs, but refused to permit CenterPoint Houston to recover a
performance bonus of $2 million on approximately $10 million in 2008
energy efficiency costs expended pursuant to the terms of a settlement agreement
reached in CenterPoint Houston’s 2006 rate proceeding. CenterPoint
Houston has appealed the denial of the full 2008 performance bonus to the
district court in Travis County, Texas, where the case remains
pending.
CenterPoint Houston Rate
Agreement. CenterPoint Houston’s transmission and distribution
rates are subject to the terms of a Settlement Agreement effective in October
2006. The Settlement Agreement provides that, until June 30, 2010,
CenterPoint Houston will not seek to increase its base rates and the other
parties will not petition to decrease those rates. The rate freeze is subject to
adjustment for certain limited matters, including the results of the appeals of
the True-Up Order, the implementation of charges associated with
securitizations, the impact of severe weather such as hurricanes and certain
other force majeure events. CenterPoint Houston must make a new base rate filing
not later than June 30, 2010, based on a test year ended December 31, 2009,
unless the staff of the Texas Utility Commission and certain cities notify it
that such a filing is unnecessary.
Natural
Gas Distribution
In almost
all communities in which Gas Operations provides natural gas distribution
services, it operates under franchises, certificates or licenses obtained from
state and local authorities. The original terms of the franchises, with various
expiration dates, typically range from 10 to 30 years, although franchises
in Arkansas are perpetual. Gas Operations expects to be able to renew expiring
franchises. In most cases, franchises to provide natural gas utility services
are not exclusive.
Substantially
all of Gas Operations is subject to cost-of-service regulation by the relevant
state public utility commissions and, in Texas, by the Railroad Commission of
Texas (Railroad Commission) and those municipalities served by Gas Operations
that have retained original jurisdiction.
Texas. In March 2008, Gas
Operations filed a request to change its rates with the Railroad Commission and
the 47 cities in its Texas Coast service territory, an area consisting of
approximately 230,000 customers in cities and communities on the outskirts of
Houston. In 2008, Gas Operations implemented rates increasing annual revenues by
approximately $3.5 million. The implemented rates were contested by 9
cities in an appeal to the 353rd District Court in Travis County, Texas. In
January 2010, that court reversed the Railroad Commission’s order in part and
remanded the matter to the Railroad Commission. The court concluded that
the Railroad Commission did not have statutory authority to impose on the
complaining cities the cost of service adjustment mechanism which the Railroad
Commission had approved in its order. Certain parties filed a motion to
modify the district court’s judgment and a final decision is not expected until
April 2010. We and CERC do not expect the outcome of this matter to have a
material adverse impact on our financial condition, results of operations or
cash flows or those of CERC.
In July 2009, Gas Operations filed a request to change its rates with the
Railroad Commission and the 29 cities in its Houston service territory,
consisting of approximately 940,000 customers in and around Houston. The request
seeks to establish uniform rates, charges and terms and conditions of service
for the cities and environs of the Houston service territory. As finally
submitted to the Railroad Commission and the cities, the proposed new rates
would result in an overall increase in annual revenue of $20.4 million,
excluding carrying costs on gas inventory of approximately $2 million. In
January 2010, Gas Operations withdrew its request for an annual cost of service
adjustment mechanism due to the uncertainty caused by the court’s ruling in the
above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission
issued its decision authorizing a revenue increase of $5.1 million annually,
reflecting reduced depreciation rates of $1.2 million. The hearing
examiner also recommended a surcharge of $0.9 million per year to recover
Hurricane Ike costs over three years.
16
identified
as a result of revisions to previously approved calculations of unrecovered
purchased gas costs. Following that denial, Gas Operations recorded a
$21 million adjustment to reduce pre-tax earnings in the fourth quarter of
2006 and reduced the regulatory asset related to these costs by an equal amount.
In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas
Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s
decision, and in May 2008 that court ruled that the MPUC had been arbitrary and
capricious in denying Gas Operations a waiver. The MPUC sought further review of
the court of appeals decision from the Minnesota Supreme Court. In
July 2009, the Minnesota Supreme Court reversed the decision of the Minnesota
Court of Appeals and upheld the MPUC’s decision to deny the requested variance.
The court’s decision had no negative impact on our financial condition, results
of operations or cash flows, as the costs at issue were written off at the time
they were disallowed.
In
November 2008, Gas Operations filed a request with the MPUC to increase its
rates for utility distribution service by $59.8 million annually. In
addition, Gas Operations sought an adjustment mechanism that would annually
adjust rates to reflect changes in use per customer. In December 2008, the
MPUC accepted the case and approved an interim rate increase of
$51.2 million, which became effective on January 2, 2009, subject to
refund. In January 2010, the MPUC issued its decision authorizing a revenue
increase of $41 million per year, with an overall rate of return of 8.09%
(10.24% return on equity). The difference between the rates approved by the MPUC
and amounts collected under the interim rates, $10 million as of December
31, 2009, is recorded in other current liabilities and will be refunded to
customers. The MPUC also authorized Gas Operations to implement a pilot program
for residential and small volume commercial customers that is intended to
decouple gas revenues from customers’ natural gas usage. In February 2010, CERC
filed a request for rehearing of the order by the MPUC. No other
party to the case filed such a request. CERC and CenterPoint Energy
do not expect a final order to be issued in this proceeding until spring
2010.
Mississippi. In
July 2009, Gas Operations filed a request to increase its rates for utility
distribution service with the Mississippi Public Service Commission (MPSC). In
November 2009, as part of a settlement agreement in which the MPSC approved Gas
Operations’ retention of the compensation paid under the terms of an asset
management agreement, Gas Operations withdrew its rate request.
Department
of Transportation
In
December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement
and Safety Act of 2006 (2006 Act), which reauthorized the programs adopted under
the Pipeline Safety Improvement Act of 2002 (2002 Act). These
programs included several requirements related to ensuring pipeline safety, and
a requirement to assess the integrity of pipeline transmission facilities in
areas of high population concentration. Under the legislation, remediation
activities are to be performed over a 10-year period. Our pipeline subsidiaries
are on schedule to comply with the timeframe mandated for completion of
integrity assessment and remediation.
Pursuant
to the 2002 Act, and then the 2006 Act, the Pipeline and Hazardous Materials
Safety Administration (PHMSA) of the U.S. Department of Transportation (DOT) has
adopted a number of rules concerning, among other things, distinguishing between
gathering lines and transmission facilities, requiring certain design and
construction features in new and replaced lines to reduce corrosion and
requiring pipeline operators to amend existing written operations and
maintenance procedures and operator qualification programs.
We
anticipate that compliance with these regulations and performance of the
remediation activities by CERC’s interstate and intrastate pipelines, and
natural gas distribution companies will require increases in both capital
expenditures and operating costs. The level of expenditures will depend upon
several factors, including age, location and operating pressures of the
facilities. Based on our interpretation of the rules written to date and
preliminary technical reviews, we believe compliance will require annual
expenditures (capital and operating costs combined) of approximately
$16 million to $18 million during the next three years.
ENVIRONMENTAL
MATTERS
Our
operations are subject to stringent and complex laws and regulations pertaining
to health, safety and the environment. As an owner or operator of natural gas
pipelines and distribution systems, gas gathering and processing systems, and
electric transmission and distribution systems, we must comply with these laws
and regulations at the federal, state and local levels. These laws and
regulations can restrict or impact our business activities in many ways, such
as:
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•
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restricting
the way we can handle or dispose of
wastes;
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•
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limiting
or prohibiting construction activities in sensitive areas such as
wetlands, coastal regions or areas inhabited by endangered
species;
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•
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requiring
remedial action to mitigate pollution conditions caused by our operations
or attributable to former operations;
and
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•
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enjoining
the operations of facilities deemed in non-compliance with permits issued
pursuant to such environmental laws and
regulations.
|
In order
to comply with these requirements, we may need to spend substantial amounts and
devote other resources from time to time to:
|
|
•
|
construct
or acquire new equipment;
|
|
|
•
|
acquire
permits for facility operations;
|
|
|
•
|
modify
or replace existing and proposed equipment;
and
|
|
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•
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clean
up or decommission waste disposal areas, fuel storage and management
facilities and other locations and
facilities.
|
Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial actions and the
issuance of orders enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to clean up and
restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.
The trend
in environmental regulation is to place more restrictions and limitations on
activities that may affect the environment, and thus there can be no assurance
as to the amount or timing of future expenditures for environmental compliance
or remediation, and actual future expenditures may be different from the amounts
we currently anticipate. We try to anticipate future regulatory requirements
that might be imposed and plan accordingly to remain in compliance with changing
environmental laws and regulations and to minimize the costs of such
compliance.
Based on
current regulatory requirements and interpretations, we do not believe that
compliance with federal, state or local environmental laws and regulations will
have a material adverse effect on our business, financial position, results of
operations or cash flows. In addition, we believe that our current environmental
remediation activities will not materially interrupt or diminish our operational
ability. We cannot assure you, however, that future events, such as changes in
existing laws, the promulgation of new laws, or the development or discovery of
new facts or conditions will not cause us to incur significant costs. The
following is a discussion of all material environmental and safety laws and
regulations that relate to our operations. We believe that we are in substantial
compliance with all of these environmental laws and regulations.
Global
Climate Change
In recent
years, there has been increasing public debate regarding the potential impact on
global climate change by various "greenhouse gases" such as carbon dioxide, a
byproduct of burning fossil fuels, and methane, the principal component of the
natural gas that we transport and deliver to customers. Legislation to regulate
emissions of greenhouse gases has been introduced in Congress, and there has
been a wide-ranging policy debate, both nationally and internationally,
regarding the impact of these gases and possible means for their regulation.
Some of the proposals would require industries such as the utility industry to
meet stringent new standards that would require substantial reductions in carbon
emissions. Those reductions could be costly and difficult to implement. Some
proposals would provide for credits to those who reduce emissions below certain
levels and would allow those credits to be traded and/or sold to
others. In addition, efforts have been made and continue to be made
in the international community toward the adoption of international treaties or
protocols that would address global climate change issues, such as the United
Nations Climate Change Conference in Copenhagen in 2009. Also, the
U.S. Environmental Protection Agency (EPA) has undertaken new efforts to collect
information regarding greenhouse gas emissions and their effects. Recently, the
EPA declared that certain greenhouse gases represent an endangerment to human
health and proposed to expand its regulations relating to those
emissions.
It is too
early to determine whether, or in what form, further regulatory action regarding
greenhouse gas emissions will be adopted or what specific impacts a new
regulatory action might have on us and our subsidiaries. However, as a
distributor and transporter of natural gas and consumer of natural gas in its
pipeline and gathering businesses, CERC’s revenues, operating costs and capital
requirements could be adversely affected as a result of any regulatory action
that would require installation of new control technologies or a modification of
its operations or would have the effect of reducing the consumption of natural
gas. Our electric transmission and distribution business, in contrast to some
electric utilities, does not generate electricity and thus is not directly
exposed to the risk of high capital costs and regulatory uncertainties that face
electric utilities that burn fossil fuels to generate
electricity. Nevertheless, CenterPoint Houston’s revenues could be
adversely affected to the extent any resulting regulatory action has the effect
of reducing consumption of electricity by ultimate consumers within its service
territory. Likewise, incentives to conserve energy or use energy sources other
than natural gas could result in a decrease in demand for our
services. Conversely, regulatory actions that effectively promote the
consumption of natural gas because of its lower emission characteristics, would
be expected to beneficially affect CERC and its natural gas-related
businesses. At this point in time, however, it would be speculative
to try to quantify the magnitude of the impacts from possible new regulatory
actions related to greenhouse gas emissions, either positive or negative, on our
businesses.
To the
extent climate changes occur, our businesses may be adversely impacted, though
we believe any such impacts are likely to occur very gradually and hence would
be difficult to quantify with specificity. To the extent global
climate change results in warmer temperatures in our service territories,
financial results from our natural gas distribution businesses could be
adversely affected through lower gas sales, and our gas transmission and field
services businesses could experience lower revenues. On the other
hand, warmer temperatures in our electric service territory may increase our
revenues from transmission and distribution through increased demand for
electricity for cooling. Another possible climate change that has
been widely discussed in recent years is the possibility of more frequent and
more severe weather events, such as hurricanes or tornadoes. Since
many of our facilities are located along or near the Gulf Coast, increased or
more severe hurricanes or tornadoes can increase our costs to repair damaged
facilities and restore service to our customers. When we cannot
deliver electricity or natural gas to customers or our customers cannot receive
our services, our financial results can be impacted by lost revenues, and we
generally must seek approval from regulators to recover restoration
costs. To the extent we are unable to recover those costs, or if
higher rates resulting from our recovery of such costs result in reduced demand
for our services, our future financial results may be adversely
impacted.
Air
Emissions
Our
operations are subject to the federal Clean Air Act and comparable state laws
and regulations. These laws and regulations regulate emissions of air pollutants
from various industrial sources, including our processing plants and compressor
stations, and also impose various monitoring and reporting requirements. Such
laws and regulations may require that we obtain pre-approval for the
construction or modification of certain projects or facilities expected to
produce air emissions or result in the increase of existing air emissions,
obtain and strictly comply with air
19
permits
containing various emissions and operational limitations, or utilize specific
emission control technologies to limit emissions. Our failure to comply with
these requirements could subject us to monetary penalties, injunctions,
conditions or restrictions on operations, and potentially criminal enforcement
actions. We may be required to incur certain capital expenditures in the future
for air pollution control equipment in connection with obtaining and maintaining
operating permits and approvals for air emissions. In recent years
the EPA has adopted amendments to its regulations regarding maximum achievable
control technology for stationary internal combustion engines (sometimes
referred to as the RICE MACT rule) and continues to consider additional
amendments. Compressors used by our Pipelines and Field Services
segments are affected by these rules. While the final structure and
effective dates of these revised rules are still uncertain, we currently believe
the rules, if adopted in their current form and on the anticipated schedule,
could require expenditures over the next 3 years of less than $100 million
in order to ensure our compliance with the revised rules. We believe,
however, that our operations will not be materially adversely affected by such
requirements.
Water
Discharges
Our
operations are subject to the Federal Water Pollution Control Act of 1972, as
amended, also known as the Clean Water Act, and analogous state laws and
regulations. These laws and regulations impose detailed requirements and strict
controls regarding the discharge of pollutants into waters of the United States.
The unpermitted discharge of pollutants, including discharges resulting from a
spill or leak incident, is prohibited. The Clean Water Act and regulations
implemented thereunder also prohibit discharges of dredged and fill material in
wetlands and other waters of the United States unless authorized by an
appropriately issued permit. Any unpermitted release of petroleum or other
pollutants from our pipelines or facilities could result in fines or penalties
as well as significant remedial obligations.
Hazardous
Waste
Our
operations generate wastes, including some hazardous wastes, that are subject to
the federal Resource Conservation and Recovery Act (RCRA), and comparable state
laws, which impose detailed requirements for the handling, storage, treatment
and disposal of hazardous and solid waste. RCRA currently exempts many natural
gas gathering and field processing wastes from classification as hazardous
waste. Specifically, RCRA excludes from the definition of hazardous waste waters
produced and other wastes associated with the exploration, development or
production of crude oil and natural gas. However, these oil and gas exploration
and production wastes are still regulated under state law and the less stringent
non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes
such as paint wastes, waste solvents, laboratory wastes and waste compressor
oils may be regulated as hazardous waste. The transportation of natural gas in
pipelines may also generate some hazardous wastes that would be subject to RCRA
or comparable state law requirements.
Liability
for Remediation
The
Comprehensive Environmental Response, Compensation and Liability Act of 1980, as
amended (CERCLA), also known as "Superfund," and comparable state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons responsible for the release of hazardous substances
into the environment. Such classes of persons include the current and past
owners or operators of sites where a hazardous substance was released and
companies that disposed or arranged for the disposal of hazardous substances at
offsite locations such as landfills. Although petroleum, as well as natural gas,
is excluded from CERCLA’s definition of a "hazardous substance," in the course
of our ordinary operations we generate wastes that may fall within the
definition of a "hazardous substance." CERCLA authorizes the EPA and, in some
cases, third parties to take action in response to threats to the public health
or the environment and to seek to recover from the responsible classes of
persons the costs they incur. Under CERCLA, we could be subject to joint and
several liability for the costs of cleaning up and restoring sites where
hazardous substances have been released, for damages to natural resources, and
for the costs of certain health studies.
Liability
for Preexisting Conditions
Manufactured Gas Plant Sites.
CERC and its predecessors operated manufactured gas plants (MGPs) in the past.
In Minnesota, CERC has completed remediation on two sites, other than ongoing
monitoring and water treatment. There are five remaining sites in CERC’s
Minnesota service territory. CERC believes that it has no liability with respect
to two of these sites.
At
December 31, 2009, CERC had accrued $14 million for remediation of
these Minnesota sites and the estimated range of possible remediation costs for
these sites was $4 million to $35 million based on remediation
continuing for 30 to 50 years. The cost estimates are based on studies of a site
or industry average costs for remediation of sites of similar size. The actual
remediation costs will be dependent upon the number of sites to be remediated,
the participation of other potentially responsible parties (PRPs), if any, and
the remediation methods used. CERC has utilized an environmental expense tracker
mechanism in its rates in Minnesota to recover estimated costs in excess of
insurance recovery. As of December 31, 2009, CERC had collected
$13 million from insurance companies and rate payers to be used for future
environmental remediation. In January 2010, as part of its Minnesota
rate case decision, the MPUC eliminated the environmental expense tracker
mechanism and ordered amounts previously collected from ratepayers and related
carrying costs refunded to customers. As of December 31, 2009, the
balance in the environmental expense tracker account was
$8.7 million. The MPUC provided for the inclusion in rates of
approximately $285,000 annually to fund normal on-going remediation
costs. CERC was not required to refund to customers the amount
collected from insurance companies, $4.6 million at December 31, 2009, to
be used to mitigate future environmental costs. The MPUC further gave
assurance that any reasonable and prudent environmental clean-up costs CERC
incurs in the future will be rate-recoverable under normal regulatory principles
and procedures. This provision had no effect on
earnings.
In
addition to the Minnesota sites, the United States Environmental Protection
Agency and other regulators have investigated MGP sites that were owned or
operated by CERC or may have been owned by one of its former affiliates. CERC
has been named as a defendant in a lawsuit filed in the United States District
Court, District of Maine, under which contribution is sought by private parties
for the cost to remediate former MGP sites based on the previous ownership of
such sites by former affiliates of CERC or its divisions. CERC has also been
identified as a PRP by the State of Maine for a site that is the subject of the
lawsuit. In June 2006, the federal district court in Maine ruled that the
current owner of the site is responsible for site remediation but that an
additional evidentiary hearing would be required to determine if other
potentially responsible parties, including CERC, would have to contribute to
that remediation. In September 2009, the federal district court granted CERC’s
motion for summary judgment in the proceeding. Although it is likely
that the plaintiff will pursue an appeal from that dismissal, further action
will not be taken until the district court disposes of claims against other
defendants in the case. CERC believes it is not liable as a former owner or
operator of the site under CERCLA and applicable state statutes, and is
vigorously contesting the suit and its designation as a PRP. We and
CERC do not expect the ultimate outcome to have a material adverse impact on the
financial condition, results of operations or cash flows of either us or
CERC.
Mercury Contamination. Our
pipeline and distribution operations have in the past employed elemental mercury
in measuring and regulating equipment. It is possible that small amounts of
mercury may have been spilled in the course of normal maintenance and
replacement operations and that these spills may have contaminated the immediate
area with elemental mercury. We have found this type of contamination at some
sites in the past, and we have conducted remediation at these sites. It is
possible that other contaminated sites may exist and that remediation costs may
be incurred for these sites. Although the total amount of these costs is not
known at this time, based on our experience and that of others in the natural
gas industry to date and on the current regulations regarding remediation of
these sites, we believe that the costs of any remediation of these sites will
not be material to our financial condition, results of operations or cash
flows.
Asbestos. Some facilities
owned by us contain or have contained asbestos insulation and other
asbestos-containing materials. We or our subsidiaries have been named, along
with numerous others, as a defendant in lawsuits filed by a number of
individuals who claim injury due to exposure to asbestos. Some of the claimants
have worked at locations owned by us, but most existing claims relate to
facilities previously owned by our subsidiaries. We anticipate that additional
claims like those received may be asserted in the future. In 2004, we sold our
generating business, to which most of these claims relate, to Texas Genco LLC,
which is now known as NRG Texas LP. Under the terms of the arrangements
regarding separation of the generating business from us and our sale to
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NRG Texas
LP, ultimate financial responsibility for uninsured losses from claims relating
to the generating business has been assumed by NRG Texas LP, but we have agreed
to continue to defend such claims to the extent they are covered by insurance
maintained by us, subject to reimbursement of the costs of such defense from NRG
Texas LP. Although their ultimate outcome cannot be predicted at this time, we
intend to continue vigorously contesting claims that we do not consider to have
merit and do not expect, based on our experience to date, these matters, either
individually or in the aggregate, to have a material adverse effect on our
financial condition, results of operations or cash flows.
Groundwater Contamination
Litigation. Predecessor entities of CERC, along with several other
entities, are defendants in litigation, St. Michel Plantation, LLC, et al,
v. White, et al., pending in civil district court in Orleans Parish,
Louisiana. In the lawsuit, the plaintiffs allege that their property in
Terrebonne Parish, Louisiana suffered salt water contamination as a result of
oil and gas drilling activities conducted by the defendants. Although a
predecessor of CERC held an interest in two oil and gas leases on a portion of
the property at issue, neither it nor any other CERC entities drilled or
conducted other oil and gas operations on those leases. In January 2009,
CERC and the plaintiffs reached agreement on the terms of a settlement that, if
ultimately approved by the Louisiana Department of Natural Resources, is
expected to resolve this litigation. We and CERC do not expect the outcome of
this litigation to have a material adverse impact on the financial condition,
results of operations or cash flows of either us or CERC.
Other Environmental. From
time to time we have received notices from regulatory authorities or others
regarding our status as a PRP in connection with sites found to require
remediation due to the presence of environmental contaminants. In addition, we
have been named from time to time as a defendant in litigation related to such
sites. Although the ultimate outcome of such matters cannot be predicted at this
time, we do not expect, based on our experience to date, these matters, either
individually or in the aggregate, to have a material adverse effect on our
financial condition, results of operations or cash flows.
EMPLOYEES
As of
December 31, 2009, we had 8,810 full-time employees. The following
table sets forth the number of our employees by business segment:
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Business
Segment
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Number
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Number
Represented
by
Unions or
Other
Collective
Bargaining
Groups
|
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Electric
Transmission & Distribution
|
2,843 | 1,249 | ||||||
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Natural
Gas Distribution
|
3,618 | 1,384 | ||||||
|
Competitive
Natural Gas Sales and Services
|
130 | - | ||||||
|
Interstate
Pipelines
|
689 | - | ||||||
|
Field
Services
|
241 | - | ||||||
|
Other
Operations
|
1,289 | - | ||||||
|
Total
|
8,810 | 2,633 | ||||||
As of
December 31, 2009, approximately 30% of our employees are subject to
collective bargaining agreements. One of the collective bargaining agreements
covering approximately 14% of our employees, International Brotherhood of
Electrical Workers Union Local No. 66, is scheduled to expire in May 2010. We
have a good relationship with this bargaining unit and expect to negotiate a new
agreement in 2010.
EXECUTIVE
OFFICERS
(as
of February 15, 2010)
|
Name
|
Age
|
Title
|
||
|
David
M. McClanahan
|
60
|
President
and Chief Executive Officer and Director
|
||
|
Scott
E. Rozzell
|
60
|
Executive
Vice President, General Counsel and Corporate Secretary
|
||
|
Gary
L. Whitlock
|
60
|
Executive
Vice President and Chief Financial Officer
|
||
|
C.
Gregory Harper
|
45
|
Senior
Vice President and Group President, CenterPoint Energy Pipelines and Field
Services
|
||
|
Thomas
R. Standish
|
60
|
Senior
Vice President and Group President - Regulated
Operations
|
David M. McClanahan has been
President and Chief Executive Officer and a director of CenterPoint Energy since
September 2002. He served as Vice Chairman of Reliant Energy, Incorporated
(Reliant Energy) from October 2000 to September 2002 and as President and Chief
Operating Officer of Reliant Energy’s Delivery Group from April 1999 to
September 2002. He previously served as Chairman of the Board of Directors of
ERCOT, Chairman of the Board of the University of St. Thomas in Houston and
Chairman of the Board of the American Gas Association. He currently serves on
the boards of the Edison Electric Institute and the American Gas
Association.
Scott E. Rozzell has served as
Executive Vice President, General Counsel and Corporate Secretary of CenterPoint
Energy since September 2002. He served as Executive Vice President and General
Counsel of the Delivery Group of Reliant Energy from March 2001 to September
2002. Before joining Reliant Energy in 2001, Mr. Rozzell was a senior
partner in the law firm of Baker Botts L.L.P. He currently serves on the Board
of Directors of the Association of Electric Companies of Texas.
Gary L. Whitlock has served as
Executive Vice President and Chief Financial Officer of CenterPoint Energy since
September 2002. He served as Executive Vice President and Chief Financial
Officer of the Delivery Group of Reliant Energy from July 2001 to September
2002. Mr. Whitlock served as the Vice President, Finance and Chief
Financial Officer of Dow AgroSciences, a subsidiary of The Dow Chemical Company,
from 1998 to 2001.
C. Gregory Harper has served
as Senior Vice President and Group President of CenterPoint Energy Pipelines and
Field Services since December 2008. Before joining CenterPoint Energy in 2008,
Mr. Harper served as President, Chief Executive Officer and as a Director of
Spectra Energy Partners, LP from March 2007 to December 2008. From January
2007 to March 2007, Mr. Harper was Group Vice President of Spectra Energy Corp.,
and he was Group Vice President of Duke Energy from January 2004 to December
2006. Mr. Harper
served as Senior Vice President of Energy Marketing and Management for Duke
Energy North America from January 2003 until January 2004 and Vice President of
Business Development for Duke Energy Gas Transmission and Vice President of East
Tennessee Natural Gas, LLC from March 2002 until January 2003. He currently
serves on the Board of Directors of the Interstate Natural Gas Association of
America.
Thomas R. Standish has served
as Senior Vice President and Group President-Regulated Operations of CenterPoint
Energy since August 2005, having previously served as Senior Vice President and
Group President and Chief Operating Officer of CenterPoint Houston from June
2004 to August 2005 and as President and Chief Operating Officer of CenterPoint
Houston from August 2002 to June 2004. He served as President and Chief
Operating Officer for both electricity and natural gas for Reliant Energy’s
Houston area from 1999 to August 2002.
Item 1A. Risk Factors
We are a
holding company that conducts all of our business operations through
subsidiaries, primarily CenterPoint Houston and CERC. The following, along with
any additional legal proceedings identified or incorporated by reference in
Item 3 of this report, summarizes the principal risk factors associated
with the businesses conducted by each of these subsidiaries:
Risk
Factors Affecting Our Electric Transmission & Distribution
Business
CenterPoint
Houston may not be successful in ultimately recovering the full value of its
true-up components, which could result in the elimination of certain tax
benefits and could have an adverse impact on CenterPoint Houston’s results of
operations, financial condition and cash flows.
In March
2004, CenterPoint Houston filed its true-up application with the Texas Utility
Commission, requesting recovery of $3.7 billion, excluding interest, as
allowed under the Texas electric restructuring law. In December 2004, the Texas
Utility Commission issued its True-Up Order allowing CenterPoint Houston to
recover a true-up balance of approximately $2.3 billion, which included
interest through August 31, 2004, and provided for adjustment of the amount
to be recovered to include interest on the balance until recovery, along with
the principal portion of additional EMCs returned to customers after
August 31, 2004 and certain other adjustments.
CenterPoint
Houston and other parties filed appeals of the True-Up Order to a district court
in Travis County, Texas. In August 2005, that court issued its judgment on the
various appeals. In its judgment, the district court:
|
|
•
|
reversed
the Texas Utility Commission’s ruling that had denied recovery of a
portion of the capacity auction true-up
amounts;
|
|
|
•
|
reversed
the Texas Utility Commission’s ruling that precluded CenterPoint Houston
from recovering the interest component of the EMCs paid to REPs;
and
|
|
|
•
|
affirmed
the True-Up Order in all other
respects.
|
The
district court’s decision would have had the effect of restoring approximately
$650 million, plus interest, of the $1.7 billion the Texas Utility
Commission had disallowed from CenterPoint Houston’s initial
request.
CenterPoint
Houston and other parties appealed the district court’s judgment to the Texas
Third Court of Appeals, which issued its decision in December 2007. In its
decision, the court of appeals:
|
|
•
|
reversed
the district court’s judgment to the extent it restored the capacity
auction true-up amounts;
|
|
|
•
|
reversed
the district court’s judgment to the extent it upheld the Texas Utility
Commission’s decision to allow CenterPoint Houston to recover EMCs paid to
RRI;
|
|
|
•
|
ordered
that the tax normalization issue described below be remanded to the Texas
Utility Commission as requested by the Texas Utility Commission;
and
|
|
|
•
|
affirmed
the district court’s judgment in all other
respects.
|
In April
2008, the court of appeals denied all motions for rehearing and reissued
substantially the same opinion as it had rendered in December 2007.
In June
2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the
court of appeals decision. In its petition, CenterPoint Houston seeks reversal
of the parts of the court of appeals decision that (i) denied recovery of EMCs
paid to RRI, (ii) denied recovery of the capacity auction true-up amounts
allowed by the district court, (iii) affirmed the Texas Utility Commission’s
rulings that denied recovery of approximately $378 million related to
depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit
CenterPoint Houston to utilize the partial stock valuation methodology for
determining the market value of its former generation assets. Two other
petitions for review were filed with the Texas Supreme Court by other parties to
the appeal. In those petitions parties contend that (i) the Texas Utility
Commission was without authority to fashion the methodology it used for valuing
the former generation assets after it had determined that CenterPoint Houston
could not use the partial stock valuation method, (ii) in fashioning the method
it used for valuing the former generating assets, the Texas Utility Commission
deprived parties of their due process rights and an opportunity to be heard,
(iii) the net book value of the generating assets should have been adjusted
downward due to the impact of a purchase option that had been granted to RRI,
(iv) CenterPoint Houston should not have been permitted to recover
24
construction
work in progress balances without proving those amounts in the manner required
by law and (v) the Texas Utility Commission was without authority to award
interest on the capacity auction true up award.
In June
2009, the Texas Supreme Court granted the petitions for review of the court of
appeals decision. Oral argument before the court was held in October
2009. Although we and CenterPoint Houston believe that CenterPoint
Houston’s true-up request is consistent with applicable statutes and regulations
and, accordingly, that it is reasonably possible that it will be successful in
its appeal to the Texas Supreme Court, we can provide no assurance as to the
ultimate court rulings on the issues to be considered in the appeal or with
respect to the ultimate decision by the Texas Utility Commission on the tax
normalization issue described below.
To
reflect the impact of the True-Up Order, in 2004 and 2005, we recorded a net
after-tax extraordinary loss of $947 million. No amounts related to the
district court’s judgment or the decision of the court of appeals have been
recorded in our consolidated financial statements. However, if the court of
appeals decision is not reversed or modified as a result of further review by
the Texas Supreme Court, we anticipate that we would be required to record an
additional loss to reflect the court of appeals decision. The amount of that
loss would depend on several factors, including ultimate resolution of the tax
normalization issue described below and the calculation of interest on any
amounts CenterPoint Houston ultimately is authorized to recover or is required
to refund beyond the amounts recorded based on the True-Up Order, but could
range from $180 million to $410 million (pre-tax) plus interest
subsequent to December 31, 2009.
In the
True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s
stranded cost recovery by approximately $146 million, which was included in
the extraordinary loss discussed above, for the present value of certain
deferred tax benefits associated with its former electric generation assets. We
believe that the Texas Utility Commission based its order on proposed
regulations issued by the IRS in March 2003 that would have allowed utilities
owning assets that were deregulated before March 4, 2003 to make a
retroactive election to pass the benefits of ADITC and EDFIT back to customers.
However, the IRS subsequently withdrew those proposed normalization regulations
and, in March 2008, adopted final regulations that would not permit utilities
like CenterPoint Houston to pass the tax benefits back to customers without
creating normalization violations. In addition, we received a PLR from the IRS
in August 2007, prior to adoption of the final regulations, that confirmed that
the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded
cost recovery by $146 million for ADITC and EDFIT would cause normalization
violations with respect to the ADITC and EDFIT.
If the
Texas Utility Commission’s order relating to the ADITC reduction is not reversed
or otherwise modified on remand so as to eliminate the normalization violation,
the IRS could require us to pay an amount equal to CenterPoint Houston’s
unamortized ADITC balance as of the date that the normalization violation is
deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the
ability to elect accelerated tax depreciation benefits beginning in the taxable
year that the normalization violation is deemed to have occurred. Such
treatment, if required by the IRS, could have a material adverse impact on our
results of operations, financial condition and cash flows in addition to any
potential loss resulting from final resolution of the True-Up Order. In its
opinion, the court of appeals ordered that this issue be remanded to the Texas
Utility Commission, as that commission requested. No party has challenged that
order by the court of appeals although the Texas Supreme Court has the authority
to consider all aspects of the rulings above, not just those challenged
specifically by the appellants. We and CenterPoint Houston will continue to
pursue a favorable resolution of this issue through the appellate and
administrative process. Although the Texas Utility Commission has not previously
required a company subject to its jurisdiction to take action that would result
in a normalization violation, no prediction can be made as to the ultimate
action the Texas Utility Commission may take on this issue on
remand.
CenterPoint
Houston’s receivables are concentrated in a small number of REPs, and any delay
or default in payment could adversely affect CenterPoint Houston’s cash flows,
financial condition and results of operations.
CenterPoint
Houston’s receivables from the distribution of electricity are collected from
REPs that supply the electricity CenterPoint Houston distributes to their
customers. As of December 31, 2009, CenterPoint Houston did business with
approximately 80 REPs. Adverse economic conditions, structural problems in the
market served by ERCOT or financial difficulties of one or more REPs could
impair the ability of these REPs to pay for CenterPoint Houston’s services or
could cause them to delay such payments. CenterPoint Houston depends on these
REPs to remit payments on a timely basis. Applicable regulatory provisions
require that customers be shifted to a provider of
25
last
resort if a REP cannot make timely payments. Applicable Texas Utility Commission
regulations significantly limit the extent to which CenterPoint Houston can
apply normal commercial terms or otherwise seek credit protection from firms
desiring to provide retail electric service in its service territory, and thus
remains at risk for payments not made prior to the shift to the provider of last
resort. Although the Texas Utility Commission revised its regulations in 2009 to
(i) increase the financial qualifications from REPs that began selling power
after January 1, 2009, and (ii) authorize utilities to defer bad debts resulting
from defaults by REPs for recovery in a future rate case, significant bad debts
may be realized and unpaid amounts may not be timely recovered. A subsidiary of
NRG Energy, Inc., NRG Retail LLC, acquired the Texas retail business of RRI, and
its subsidiaries are together considered the largest REP in CenterPoint
Houston’s service territory. Approximately 41% of CenterPoint Houston’s
$139 million in billed receivables from REPs at December 31, 2009 was owed
by subsidiaries of NRG Retail LLC. NRG Energy, Inc.’s credit ratings are
currently below investment grade. Any delay or default in payment by
REPs could adversely affect CenterPoint Houston’s cash flows, financial
condition and results of operations. If any of these REPs were unable
to meet its obligations, it could consider, among various options, restructuring
under the bankruptcy laws, in which event any such REP might seek to avoid
honoring its obligations and claims might be made by creditors involving
payments CenterPoint Houston had received from such REP.
Rate
regulation of CenterPoint Houston’s business may delay or deny CenterPoint
Houston’s ability to earn a reasonable return and fully recover its
costs.
CenterPoint
Houston’s rates are regulated by certain municipalities and the Texas Utility
Commission based on an analysis of its invested capital and its expenses in a
test year. Thus, the rates that CenterPoint Houston is allowed to charge may not
match its expenses at any given time. The regulatory process by which rates are
determined may not always result in rates that will produce full recovery of
CenterPoint Houston’s costs and enable CenterPoint Houston to earn a reasonable
return on its invested capital.
In this
regard, pursuant to the Stipulation and Settlement Agreement approved by the
Texas Utility Commission in September 2006, until June 30, 2010 CenterPoint
Houston is limited in its ability to request retail rate relief. For more
information on the Stipulation and Settlement Agreement, please read "Business -
Regulation - State and Local Regulation - Electric Transmission &
Distribution - CenterPoint Houston Rate Agreement" in Item 1 of this Form
10-K.
Disruptions
at power generation facilities owned by third parties could interrupt
CenterPoint Houston’s sales of transmission and distribution
services.
CenterPoint
Houston transmits and distributes to customers of REPs electric power that the
REPs obtain from power generation facilities owned by third parties. CenterPoint
Houston does not own or operate any power generation facilities. If power
generation is disrupted or if power generation capacity is inadequate,
CenterPoint Houston’s sales of transmission and distribution services may be
diminished or interrupted, and its results of operations, financial condition
and cash flows could be adversely affected.
CenterPoint
Houston’s revenues and results of operations are seasonal.
A
significant portion of CenterPoint Houston’s revenues is derived from rates that
it collects from each REP based on the amount of electricity it delivers on
behalf of such REP. Thus, CenterPoint Houston’s revenues and results of
operations are subject to seasonality, weather conditions and other changes in
electricity usage, with revenues being higher during the warmer
months.
Risk
Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales
and Services, Interstate Pipelines and Field Services Businesses
Rate
regulation of CERC’s business may delay or deny CERC’s ability to earn a
reasonable return and fully recover its costs.
CERC’s
rates for Gas Operations are regulated by certain municipalities and state
commissions, and for its interstate pipelines by the FERC, based on an analysis
of its invested capital and its expenses in a test year. Thus, the rates that
CERC is allowed to charge may not match its expenses at any given time. The
regulatory process in which
26
rates are
determined may not always result in rates that will produce full recovery of
CERC’s costs and enable CERC to earn a reasonable return on its invested
capital.
CERC’s
businesses must compete with alternate energy sources, which could result in
CERC marketing less natural gas, and its interstate pipelines and field services
businesses must compete directly with others in the transportation, storage,
gathering, treating and processing of natural gas, which could lead to lower
prices and reduced volumes, either of which could have an adverse impact on
CERC’s results of operations, financial condition and cash flows.
CERC
competes primarily with alternate energy sources such as electricity and other
fuel sources. In some areas, intrastate pipelines, other natural gas
distributors and marketers also compete directly with CERC for natural gas sales
to end-users. In addition, as a result of federal regulatory changes affecting
interstate pipelines, natural gas marketers operating on these pipelines may be
able to bypass CERC’s facilities and market, sell and/or transport natural gas
directly to commercial and industrial customers. Any reduction in the amount of
natural gas marketed, sold or transported by CERC as a result of competition may
have an adverse impact on CERC’s results of operations, financial condition and
cash flows.
CERC’s
two interstate pipelines and its gathering systems compete with other interstate
and intrastate pipelines and gathering systems in the transportation and storage
of natural gas. The principal elements of competition are rates, terms of
service, and flexibility and reliability of service. They also compete
indirectly with other forms of energy, including electricity, coal and fuel
oils. The primary competitive factor is price. The actions of CERC’s competitors
could lead to lower prices, which may have an adverse impact on CERC’s results
of operations, financial condition and cash flows. Additionally, any reduction
in the volume of natural gas transported or stored may have an adverse impact on
CERC’s results of operations, financial condition and cash flows.
CERC’s
natural gas distribution and competitive natural gas sales and services
businesses are subject to fluctuations in natural gas prices, which could affect
the ability of CERC’s suppliers and customers to meet their obligations or
otherwise adversely affect CERC’s liquidity and results of
operations.
CERC is
subject to risk associated with changes in the price of natural gas. Increases
in natural gas prices might affect CERC’s ability to collect balances due from
its customers and, for Gas Operations, could create the potential for
uncollectible accounts expense to exceed the recoverable levels built into
CERC’s tariff rates. In addition, a sustained period of high natural gas prices
could (i) apply downward demand pressure on natural gas consumption in the areas
in which CERC operates thereby resulting in decreased sales volumes and revenues
and (ii) increase the risk that CERC’s suppliers or customers fail or are unable
to meet their obligations. An increase in natural gas prices would also increase
CERC’s working capital requirements by increasing the investment that must be
made in order to maintain natural gas inventory levels. Additionally,
a decrease in natural gas prices could increase the amount of collateral that
CERC must provide under its hedging arrangements.
A
decline in CERC’s credit rating could result in CERC’s having to provide
collateral in order to purchase natural gas or under its shipping or hedging
arrangements.
If CERC’s
credit rating were to decline, it might be required to post cash collateral in
order to purchase natural gas or under its shipping or hedging arrangements. If
a credit rating downgrade and the resultant cash collateral requirement were to
occur at a time when CERC was experiencing significant working capital
requirements or otherwise lacked liquidity, CERC’s results of operations,
financial condition and cash flows could be adversely affected.
The
revenues and results of operations of CERC’s interstate pipelines and field
services businesses are subject to fluctuations in the supply and price of
natural gas and natural gas liquids.
CERC’s
interstate pipelines and field services businesses largely rely on natural gas
sourced in the various supply basins located in the Mid-continent region of the
United States. The level of drilling and production activity in these regions is
dependent on economic and business factors beyond our control. The primary
factor affecting both the level of drilling activity and production volumes is
natural gas pricing. A sustained decline in natural gas prices could result in a
decrease in exploration and development activities in the regions served by our
gathering and
27
pipeline
transportation systems and our natural gas treating and processing activities. A
sustained decline could also lead producers to shut in production from their
existing wells. Other factors that impact production decisions include the level
of production costs relative to other available production, producers’ access to
needed capital and the cost of that capital, the ability of producers to obtain
necessary drilling and other governmental permits, access to drilling rigs and
regulatory changes. Because of these factors, even if new natural gas reserves
are discovered in areas served by our assets, producers may choose not to
develop those reserves or to shut in production from existing reserves. To the
extent the availability of this supply is substantially reduced, it could have
an adverse effect on CERC’s results of operations, financial condition and cash
flows.
CERC’s
revenues from these businesses are also affected by the prices of natural gas
and natural gas liquids (NGL). NGL prices generally fluctuate on a basis that
correlates to fluctuations in crude oil prices. In the past, the prices of
natural gas and crude oil have been extremely volatile, and we expect this
volatility to continue. The markets and prices for natural gas, NGLs and crude
oil depend upon factors beyond our control. These factors include supply of and
demand for these commodities, which fluctuate with changes in market and
economic conditions and other factors.
CERC’s
revenues and results of operations are seasonal.
A
substantial portion of CERC’s revenues is derived from natural gas sales and
transportation. Thus, CERC’s revenues and results of operations are subject to
seasonality, weather conditions and other changes in natural gas usage, with
revenues being higher during the winter months.
The
actual cost of pipelines under construction, future pipeline, gathering and
treating systems and related compression facilities may be significantly higher
than CERC had planned.
Subsidiaries
of CERC Corp. have been recently involved in significant pipeline construction
projects and, depending on available opportunities, may, from time to time, be
involved in additional significant pipeline construction and gathering and
treating system projects in the future. The construction of new pipelines,
gathering and treating systems and related compression facilities may require
the expenditure of significant amounts of capital, which may exceed CERC’s
estimates. These projects may not be completed at the planned cost, on schedule
or at all. The construction of new pipeline, gathering, treating or compression
facilities is subject to construction cost overruns due to labor costs, costs of
equipment and materials such as steel and nickel, labor shortages or delays,
weather delays, inflation or other factors, which could be material. In
addition, the construction of these facilities is typically subject to the
receipt of approvals and permits from various regulatory agencies. Those
agencies may not approve the projects in a timely manner or may impose
restrictions or conditions on the projects that could potentially prevent a
project from proceeding, lengthen its expected completion schedule and/or
increase its anticipated cost. As a result, there is the risk that the new
facilities may not be able to achieve CERC’s expected investment return, which
could adversely affect CERC’s financial condition, results of operations or cash
flows.
The
states in which CERC provides regulated local gas distribution may, either
through legislation or rules, adopt restrictions similar to or broader than
those under the Public Utility Holding Company Act of 1935 regarding
organization, financing and affiliate transactions that could have significant
adverse impacts on CERC’s ability to operate.
The
Public Utility Holding Company Act of 1935, to which we and our subsidiaries
were subject prior to its repeal in the Energy Policy Act of 2005, provided a
comprehensive regulatory structure governing the organization, capital
structure, intracompany relationships and lines of business that could be
pursued by registered holding companies and their member companies. Following
repeal of that Act, some states in which CERC does business have sought to
expand their own regulatory frameworks to give their regulatory authorities
increased jurisdiction and scrutiny over similar aspects of the utilities that
operate in their states. Some of these frameworks attempt to regulate financing
activities, acquisitions and divestitures, and arrangements between the
utilities and their affiliates, and to restrict the level of non-utility
business that can be conducted within the holding company structure.
Additionally they may impose record keeping, record access, employee training
and reporting requirements related to affiliate transactions and reporting in
the event of certain downgrading of the utility’s bond rating.
These
regulatory frameworks could have adverse effects on CERC’s ability to conduct
its utility operations, to finance its business and to provide cost-effective
utility service. In addition, if more than one state adopts restrictions on
similar activities, it may be difficult for CERC and us to comply with competing
regulatory requirements.
The
revenues and results of operations of CERC’s interstate pipelines and field
services businesses could be adversely impacted by new environmental regulations
governing the withdrawal, storage and use of surface water or groundwater
necessary for hydraulic fracturing of wells and the protection of water supplies
in the areas in and around shale fields.
CERC’s
interstate pipelines and field services businesses largely rely on natural gas
sourced in the various supply basins located in the Mid-continent region of the
United States. To extract natural gas from the shale fields in this
area, producers have historically used a process called hydraulic fracturing.
Recently, new environmental regulations governing the withdrawal, storage and
use of surface water or groundwater necessary for hydraulic fracturing of wells
and the protection of water supplies in the areas in and around the shale fields
have been considered by the federal government. If enacted, such
regulations could increase operating costs of the producers in these regions or
cause delays, interruptions or termination of drilling operations, all of which
could result in a decrease in demand for the services provided by CERC’s
interstate pipelines and field services businesses in the shale fields, which
could have an adverse effect on CERC’s results of operations, financial
condition and cash flows.
Risk
Factors Associated with Our Consolidated Financial Condition
If we are unable
to arrange future financings on acceptable terms, our ability to refinance
existing indebtedness could be limited.
As of
December 31, 2009, we had $10.1 billion of outstanding indebtedness on a
consolidated basis, which includes $3.0 billion of non-recourse transition
and system restoration bonds. As of December 31, 2009, approximately
$1.2 billion principal amount of this debt is required to be paid through
2012. This amount excludes principal repayments of approximately
$831 million on transition and system restoration bonds, for which a
dedicated revenue stream exists, but includes $290 million of pollution
control bonds issued on our behalf which we purchased in January 2010 (and which
may be remarketed) and $45 million of debentures redeemed in January 2010.
Our future financing activities may be significantly affected by, among other
things:
|
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•
|
the
resolution of the true-up proceedings, including, in particular, the
results of appeals to the Texas Supreme Court regarding rulings obtained
to date;
|
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•
|
general
economic and capital market
conditions;
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•
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credit
availability from financial institutions and other
lenders;
|
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•
|
investor
confidence in us and the markets in which we
operate;
|
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•
|
maintenance
of acceptable credit ratings;
|
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•
|
market
expectations regarding our future earnings and cash
flows;
|
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•
|
market
perceptions of our ability to access capital markets on reasonable
terms;
|
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•
|
our
exposure to RRI in connection with its indemnification obligations arising
in connection with its separation from us;
and
|
|
|
•
|
provisions
of relevant tax and securities
laws.
|
As of
December 31, 2009, CenterPoint Houston had outstanding approximately
$2.5 billion aggregate principal amount of general mortgage bonds,
including approximately $527 million held in trust to secure pollution
control bonds for which we are obligated and approximately $229 million
held in trust to secure pollution control bonds for
29
which
CenterPoint Houston is obligated. Additionally, CenterPoint Houston had
outstanding approximately $253 million aggregate principal amount of first
mortgage bonds, including approximately $151 million held in trust to
secure certain pollution control bonds for which we are obligated. CenterPoint
Houston may issue additional general mortgage bonds on the basis of retired
bonds, 70% of property additions or cash deposited with the trustee.
Approximately $2.1 billion of additional first mortgage bonds and general
mortgage bonds in the aggregate could be issued on the basis of retired bonds
and 70% of property additions as of December 31, 2009. However, CenterPoint
Houston has contractually agreed that it will not issue additional first
mortgage bonds, subject to certain exceptions.
Our
current credit ratings are discussed in "Management’s Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital Resources
- - Future Sources and Uses of Cash - Impact on Liquidity of a Downgrade in Credit
Ratings" in Item 7 of Part II of this report. These credit ratings may not
remain in effect for any given period of time and one or more of these ratings
may be lowered or withdrawn entirely by a rating agency. We note that these
credit ratings are not recommendations to buy, sell or hold our securities. Each
rating should be evaluated independently of any other rating. Any future
reduction or withdrawal of one or more of our credit ratings could have a
material adverse impact on our ability to access capital on acceptable
terms.
As
a holding company with no operations of our own, we will depend on distributions
from our subsidiaries to meet our payment obligations, and provisions of
applicable law or contractual restrictions could limit the amount of those
distributions.
We derive
all our operating income from, and hold all our assets through, our
subsidiaries. As a result, we will depend on distributions from our subsidiaries
in order to meet our payment obligations. In general, these subsidiaries are
separate and distinct legal entities and have no obligation to provide us with
funds for our payment obligations, whether by dividends, distributions, loans or
otherwise. In addition, provisions of applicable law, such as those limiting the
legal sources of dividends, limit our subsidiaries’ ability to make payments or
other distributions to us, and our subsidiaries could agree to contractual
restrictions on their ability to make distributions.
Our right
to receive any assets of any subsidiary, and therefore the right of our
creditors to participate in those assets, will be effectively subordinated to
the claims of that subsidiary’s creditors, including trade creditors. In
addition, even if we were a creditor of any subsidiary, our rights as a creditor
would be subordinated to any security interest in the assets of that subsidiary
and any indebtedness of the subsidiary senior to that held by us.
The
use of derivative contracts by us and our subsidiaries in the normal course of
business could result in financial losses that could negatively impact our
results of operations and those of our subsidiaries.
We and
our subsidiaries use derivative instruments, such as swaps, options, futures and
forwards, to manage our commodity, weather and financial market risks. We and
our subsidiaries could recognize financial losses as a result of volatility in
the market values of these contracts or should a counterparty fail to perform.
In the absence of actively quoted market prices and pricing information from
external sources, the valuation of these financial instruments can involve
management’s judgment or use of estimates. As a result, changes in the
underlying assumptions or use of alternative valuation methods could affect the
reported fair value of these contracts.
Risks
Common to Our Businesses and Other Risks
We
are subject to operational and financial risks and liabilities arising from
environmental laws and regulations.
Our
operations are subject to stringent and complex laws and regulations pertaining
to health, safety and the environment. As an owner or operator of natural gas
pipelines and distribution systems, gas gathering and processing systems, and
electric transmission and distribution systems, we must comply with these laws
and regulations at the federal, state and local levels. These laws and
regulations can restrict or impact our business activities in many ways, such
as:
|
|
•
|
restricting
the way we can handle or dispose of
wastes;
|
|
|
•
|
limiting
or prohibiting construction activities in sensitive areas such as
wetlands, coastal regions, or areas inhabited by endangered
species;
|
|
|
•
|
requiring
remedial action to mitigate pollution conditions caused by our operations,
or attributable to former operations;
and
|
|
|
•
|
enjoining
the operations of facilities deemed in non-compliance with permits issued
pursuant to such environmental laws and
regulations.
|
In order
to comply with these requirements, we may need to spend substantial amounts and
devote other resources from time to time to:
|
|
•
|
construct
or acquire new equipment;
|
|
|
•
|
acquire
permits for facility operations;
|
|
|
•
|
modify
or replace existing and proposed equipment;
and
|
|
|
•
|
clean
up or decommission waste disposal areas, fuel storage and management
facilities and other locations and
facilities.
|
Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial actions, and the
issuance of orders enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to clean up and
restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.
Our
insurance coverage may not be sufficient. Insufficient insurance coverage and
increased insurance costs could adversely impact our results of operations,
financial condition and cash flows.
We
currently have general liability and property insurance in place to cover
certain of our facilities in amounts that we consider appropriate. Such policies
are subject to certain limits and deductibles and do not include business
interruption coverage. Insurance coverage may not be available in the future at
current costs or on commercially reasonable terms, and the insurance proceeds
received for any loss of, or any damage to, any of our facilities may not be
sufficient to restore the loss or damage without negative impact on our results
of operations, financial condition and cash flows.
In common
with other companies in its line of business that serve coastal regions,
CenterPoint Houston does not have insurance covering its transmission and
distribution system, other than substations, because CenterPoint Houston
believes it to be cost prohibitive. In the future, CenterPoint Houston may not
be able to recover the costs incurred in restoring its transmission and
distribution properties following hurricanes or other natural disasters through
issuance of storm restoration bonds or a change in its regulated rates or
otherwise, or any such recovery may not be timely granted. Therefore,
CenterPoint Houston may not be able to restore any loss of, or damage to, any of
its transmission and distribution properties without negative impact on its
results of operations, financial condition and cash flows.
We,
CenterPoint Houston and CERC could incur liabilities associated with businesses
and assets that we have transferred to others.
Under
some circumstances, we, CenterPoint Houston and CERC could incur liabilities
associated with assets and businesses we, CenterPoint Houston and CERC no longer
own. These assets and businesses were previously owned by Reliant Energy,
Incorporated (Reliant Energy), a predecessor of CenterPoint Houston, directly or
through subsidiaries and include:
|
|
•
|
merchant
energy, energy trading and REP businesses transferred to RRI or its
subsidiaries in connection with the organization and capitalization of RRI
prior to its initial public offering in 2001;
and
|
|
|
•
|
Texas
electric generating facilities transferred to Texas Genco Holdings, Inc.
(Texas Genco) in 2004 and early
2005.
|
In
connection with the organization and capitalization of RRI, RRI and its
subsidiaries assumed liabilities associated with various assets and businesses
Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the
applicable transferee subsidiaries to indemnify, us and our subsidiaries,
including CenterPoint Houston and CERC, with respect to liabilities associated
with the transferred assets and businesses. These indemnity provisions were
intended to place sole financial responsibility on RRI and its subsidiaries for
all liabilities associated with the current and historical businesses and
operations of RRI, regardless of the time those liabilities arose. If RRI were
unable to satisfy a liability that has been so assumed in circumstances in which
Reliant Energy and its subsidiaries were not released from the liability in
connection with the transfer, we, CenterPoint Houston or CERC could be
responsible for satisfying the liability.
Prior to
the distribution of our ownership in RRI to our shareholders, CERC had
guaranteed certain contractual obligations of what became RRI’s trading
subsidiary. When the companies separated, RRI agreed to secure CERC against
obligations under the guaranties RRI had been unable to extinguish by the time
of separation. Pursuant to such agreement, as amended in December 2007, RRI has
agreed to provide to CERC cash or letters of credit as security against
CERC’s obligations under its remaining guaranties for demand charges under
certain gas transportation agreements if and to the extent changes in market
conditions expose CERC to a risk of loss on those guaranties. The present
value of the demand charges under these transportation contracts, which will be
effective until 2018, was approximately $96 million as of December 31,
2009. As of December 31, 2009, RRI was not required to provide security to
CERC. If RRI should fail to perform the contractual obligations, CERC
could have to honor its guarantee and, in such event, collateral provided as
security may be insufficient to satisfy CERC’s obligations.
RRI’s
unsecured debt ratings are currently below investment grade. If RRI were unable
to meet its obligations, it would need to consider, among various options,
restructuring under the bankruptcy laws, in which event RRI might not honor its
indemnification obligations and claims by RRI’s creditors might be made against
us as its former owner.
On May 1,
2009, RRI completed the previously announced sale of its Texas retail business
to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection with the sale,
RRI changed its name to RRI Energy, Inc. and no longer provides service as a REP
in CenterPoint Houston’s service territory. The sale does not alter RRI’s
contractual obligations to indemnify us and our subsidiaries, including
CenterPoint Houston, for certain liabilities, including their indemnification
regarding certain litigation, nor does it affect the terms of existing guaranty
arrangements for certain RRI gas transportation contracts.
Reliant
Energy and RRI are named as defendants in a number of lawsuits arising out of
sales of natural gas in California and other markets. Although these matters
relate to the business and operations of RRI, claims against Reliant Energy have
been made on grounds that include liability of Reliant Energy as a controlling
shareholder of RRI. We, CenterPoint Houston or CERC could incur liability if
claims in one or more of these lawsuits were successfully asserted against us,
CenterPoint Houston or CERC and indemnification from RRI were determined to be
unavailable or if RRI were unable to satisfy indemnification obligations owed
with respect to those claims.
In
connection with the organization and capitalization of Texas Genco, Reliant
Energy and Texas Genco entered into a separation agreement in which Texas Genco
assumed liabilities associated with the electric generation assets Reliant
Energy transferred to it. Texas Genco also agreed to indemnify, and cause the
applicable transferee subsidiaries to indemnify, us and our subsidiaries,
including CenterPoint Houston, with respect to liabilities associated with the
transferred assets and businesses. In many cases the liabilities assumed were
obligations of CenterPoint Houston, and CenterPoint Houston was not released by
third parties from these liabilities. The indemnity provisions were intended
generally to place sole financial responsibility on Texas Genco and its
subsidiaries for all liabilities associated with the current and historical
businesses and operations of Texas Genco, regardless of the time those
liabilities arose. If Texas Genco were unable to satisfy a liability that had
been so
32
assumed
or indemnified against, and provided we or Reliant Energy had not been released
from the liability in connection with the transfer, CenterPoint Houston could be
responsible for satisfying the liability.
In
connection with our sale of Texas Genco to a third party, the separation
agreement was amended to provide that Texas Genco would no longer be liable for,
and we would assume and agree to indemnify Texas Genco against, liabilities that
Texas Genco originally assumed in connection with its organization to the
extent, and only to the extent, that such liabilities are covered by certain
insurance policies held by us. Texas Genco and its related businesses now
operate as subsidiaries of NRG Energy, Inc.
We or our
subsidiaries have been named, along with numerous others, as a defendant in
lawsuits filed by a number of individuals who claim injury due to exposure to
asbestos. Some of the claimants have worked at locations owned by us, but most
existing claims relate to facilities previously owned by our subsidiaries but
currently owned by NRG Texas LP. We anticipate that additional claims like those
received may be asserted in the future. Under the terms of the arrangements
regarding separation of the generating business from us and its sale to NRG
Texas LP, ultimate financial responsibility for uninsured losses from claims
relating to the generating business has been assumed by NRG Texas LP, but we
have agreed to continue to defend such claims to the extent they are covered by
insurance maintained by us, subject to reimbursement of the costs of such
defense by NRG Texas LP.
The
unsettled conditions in the global financial system may have impacts on our
business, liquidity and financial condition that we currently cannot
predict.
The
recent credit crisis and unsettled conditions in the global financial system may
have an impact on our business, liquidity and our financial condition. Our
ability to access the capital markets may be severely restricted at a time when
we would like, or need, to access those markets, which could have an impact on
our liquidity and flexibility to react to changing economic and business
conditions. In addition, the cost of debt financing and the proceeds of equity
financing may be materially adversely impacted by these market conditions.
Defaults of lenders in our credit facilities, should they further occur, could
adversely affect our liquidity. Capital market turmoil was also reflected in
significant reductions in equity market valuations in 2008, which significantly
reduced the value of assets of our pension plan. These reductions increased
non-cash pension expense in 2009 which impacted 2009 results of operations and
may impact liquidity if contributions are made to offset reduced asset
values.
In
addition to the credit and financial market issues, a recurrence of national and
local recessionary conditions may impact our business in a variety of ways.
These include, among other things, reduced customer usage, increased customer
default rates and wide swings in commodity prices.
Climate
change legislation and regulatory initiatives could result in increased
operating costs and reduced demand for our services.
Legislation
to regulate emissions of greenhouse gases has been introduced in Congress, and
there has been a wide-ranging policy debate, both nationally and
internationally, regarding the impact of these gases and possible means for
their regulation. In addition, efforts have been made and continue to
be made in the international community toward the adoption of international
treaties or protocols that would address global climate change issues, such as
the United Nations Climate Change Conference in Copenhagen in 2009. Also, the
EPA has undertaken new efforts to collect information regarding greenhouse gas
emissions and their effects. Recently, the EPA declared that certain greenhouse
gases represent an endangerment to human health and proposed to expand its
regulations relating to those emissions. It is too early to determine
whether, or in what form, further regulatory action regarding greenhouse gas
emissions will be adopted or what specific impacts a new regulatory action might
have on us and our subsidiaries. However, as a distributor and transporter of
natural gas and consumer of natural gas in its pipeline and gathering
businesses, CERC’s revenues, operating costs and capital requirements could be
adversely affected as a result of any regulatory action that would require
installation of new control technologies or a modification of its operations or
would have the effect of reducing the consumption of natural gas. Our
electric transmission and distribution business, in contrast to some electric
utilities, does not generate electricity and thus is not directly exposed to the
risk of high capital costs and regulatory uncertainties that face electric
utilities that burn fossil fuels to generate
electricity. Nevertheless, CenterPoint Houston’s revenues could be
adversely affected to the extent any resulting regulatory action has the effect
of reducing consumption of electricity by ultimate consumers
33
within
its service territory. Likewise, incentives to conserve energy or use energy
sources other than natural gas could result in a decrease in demand for our
services.
Climate
changes could result in more frequent severe weather events and warmer
temperatures which could adversely affect the results of operations of our
businesses.
To the
extent climate changes occur, our businesses may be adversely impacted, though
we believe any such impacts are likely to occur very gradually and hence would
be difficult to quantify with specificity. To the extent global
climate change results in warmer temperatures in our service territories,
financial results from our natural gas distribution businesses could be
adversely affected through lower gas sales, and our gas transmission and field
services businesses could experience lower revenues. Another possible climate
change that has been widely discussed in recent years is the possibility of more
frequent and more severe weather events, such as hurricanes or
tornadoes. Since many of our facilities are located along or near the
Gulf Coast, increased or more severe hurricanes or tornadoes can increase our
costs to repair damaged facilities and restore service to our
customers. When we cannot deliver electricity or natural gas to
customers or our customers cannot receive our services, our financial results
can be impacted by lost revenues, and we generally must seek approval from
regulators to recover restoration costs. To the extent we are unable
to recover those costs, or if higher rates resulting from our recovery of such
costs result in reduced demand for our services, our future financial results
may be adversely impacted.
Item 1B. Unresolved Staff
Comments
Not
applicable.
Item 2. Properties
Character
of Ownership
We own or
lease our principal properties in fee, including our corporate office space and
various real property. Most of our electric lines and gas mains are located,
pursuant to easements and other rights, on public roads or on land owned by
others.
Electric
Transmission & Distribution
For
information regarding the properties of our Electric Transmission &
Distribution business segment, please read "Business - Our Business -
Electric Transmission & Distribution - Properties" in Item 1
of this report, which information is incorporated herein by
reference.
Natural
Gas Distribution
For
information regarding the properties of our Natural Gas Distribution business
segment, please read "Business - Our Business - Natural Gas
Distribution - Assets" in Item 1 of this report, which information is
incorporated herein by reference.
Competitive
Natural Gas Sales and Services
For
information regarding the properties of our Competitive Natural Gas Sales and
Services business segment, please read "Business - Our Business -
Competitive Natural Gas Sales and Services - Assets" in Item 1 of this
report, which information is incorporated herein by reference.
Interstate
Pipelines
For
information regarding the properties of our Interstate Pipelines business
segment, please read "Business - Our Business - Interstate
Pipelines - Assets" in Item 1 of this report, which information is
incorporated herein by reference.
Field
Services
For
information regarding the properties of our Field Services business segment,
please read "Business - Our Business - Field Services - Assets"
in Item 1 of this report, which information is incorporated herein by
reference.
Other
Operations
For
information regarding the properties of our Other Operations business segment,
please read "Business - Our Business - Other Operations" in
Item 1 of this report, which information is incorporated herein by
reference.
Item 3. Legal
Proceedings
For a
discussion of material legal and regulatory proceedings affecting us, please
read "Business - Regulation" and "Business - Environmental Matters" in
Item 1 of this report and Notes 3 and 10(e) to our consolidated
financial statements, which information is incorporated herein by
reference.
Item 4. Submission of Matters to a Vote of
Security Holders
There
were no matters submitted to the vote of our security holders during the fourth
quarter of 2009.
PART II
Item 5. Market for Registrant’s Common
Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
As of
February 15, 2010, our common stock was held of record by approximately
45,607 shareholders. Our common stock is listed on the New York and Chicago
Stock Exchanges and is traded under the symbol "CNP."
The
following table sets forth the high and low closing prices of the common stock
of CenterPoint Energy on the New York Stock Exchange composite tape during the
periods indicated, as reported by Bloomberg, and the cash
dividends declared in these periods.
|
Market
Price
|
Dividend
|
|||||||||||
|
Declared
|
||||||||||||
|
High
|
Low
|
Per
Share
|
||||||||||
|
2008
|
||||||||||||
|
First Quarter
|
$ | 0.1825 | ||||||||||
|
January 9
|
$ | 16.98 | ||||||||||
|
March 17
|
$ | 13.84 | ||||||||||
|
Second Quarter
|
$ | 0.1825 | ||||||||||
|
April 1
|
$ | 14.66 | ||||||||||
|
May 29
|
$ | 17.16 | ||||||||||
|
Third Quarter
|
$ | 0.1825 | ||||||||||
|
August 11
|
$ | 16.59 | ||||||||||
|
September 18
|
$ | 13.98 | ||||||||||
|
Fourth Quarter
|
$ | 0.1825 | ||||||||||
|
October 1
|
$ | 14.40 | ||||||||||
|
October 10
|
$ | 9.08 | ||||||||||
|
2009
|
||||||||||||
|
First Quarter
|
$ | 0.19 | ||||||||||
|
February 6
|
$ | 14.39 | ||||||||||
|
March 6
|
$ | 8.88 | ||||||||||
|
Second Quarter
|
$ | 0.19 | ||||||||||
|
May 27
|
$ | 9.77 | ||||||||||
|
June 29
|
$ | 11.24 | ||||||||||
|
Third Quarter
|
$ | 0.19 | ||||||||||
|
July 9
|
$ | 10.78 | ||||||||||
|
August 26
|
$ | 12.83 | ||||||||||
|
Fourth Quarter
|
$ | 0.19 | ||||||||||
|
October 2
|
$ | 12.22 | ||||||||||
|
December 28
|
$ | 14.81 | ||||||||||
The
closing market price of our common stock on December 31, 2009 was
$14.51 per share.
The
amount of future cash dividends will be subject to determination based upon our
results of operations and financial condition, our future business prospects,
any applicable contractual restrictions and other factors that our board of
directors considers relevant and will be declared at the discretion of the board
of directors.
On
January 21, 2010, we announced a regular quarterly cash dividend of
$0.195 per share, payable on March 10, 2010 to shareholders of record
on February 16, 2010.
Repurchases
of Equity Securities
During
the quarter ended December 31, 2009, none of our equity securities
registered pursuant to Section 12 of the Securities Exchange Act of 1934
were purchased by or on behalf of us or any of our "affiliated purchasers," as
defined in Rule 10b-18(a)(3) under the Securities Exchange Act of
1934.
Item 6.
Selected Financial
Data
The
following table presents selected financial data with respect to our
consolidated financial condition and consolidated results of operations and
should be read in conjunction with our consolidated financial statements and the
related notes in Item 8 of this report.
|
Year
Ended December 31,
|
||||||||||||||||||||
|
2005(1)(2)
|
2006(2)
|
2007(2)
|
2008(2)
|
2009
|
||||||||||||||||
|
(In
millions, except per share amounts)
|
||||||||||||||||||||
|
Revenues
|
$ | 9,722 | $ | 9,319 | $ | 9,623 | $ | 11,322 | $ | 8,281 | ||||||||||
|
Income
from continuing operations before extraordinary item
|
220 | 427 | 395 | 446 | 372 | |||||||||||||||
|
Discontinued
operations, net of tax
|
(3 | ) | - | - | - | - | ||||||||||||||
|
Extraordinary item,
net of tax
|
30 | - | - | - | - | |||||||||||||||
|
Net income
|
$ | 247 | $ | 427 | $ | 395 | $ | 446 | $ | 372 | ||||||||||
|
Basic
earnings (loss) per common share:
|
||||||||||||||||||||
|
Income
from continuing operations before extraordinary item
|
$ | 0.71 | $ | 1.37 | $ | 1.23 | $ | 1.32 | $ | 1.02 | ||||||||||
|
Discontinued
operations, net of tax
|
(0.01 | ) | - | - | - | - | ||||||||||||||
|
Extraordinary item,
net of tax
|
0.10 | - | - | - | - | |||||||||||||||
|
Basic earnings per
common share
|
$ | 0.80 | $ | 1.37 | $ | 1.23 | $ | 1.32 | $ | 1.02 | ||||||||||
|
Diluted
earnings (loss) per common share:
|
||||||||||||||||||||
|
Income
from continuing operations before extraordinary item
|
$ | 0.66 | $ | 1.31 | $ | 1.15 | $ | 1.30 | $ | 1.01 | ||||||||||
|
Discontinued
operations, net of tax
|
(0.01 | ) | - | - | - | - | ||||||||||||||
|
Extraordinary item,
net of tax
|
0.09 | - | - | - | - | |||||||||||||||
|
Diluted earnings per
common share
|
$ | 0.74 | $ | 1.31 | $ | 1.15 | $ | 1.30 | $ | 1.01 | ||||||||||
|
Cash dividends
declared per common share
|
$ | 0.40 | $ | 0.60 | $ | 0.68 | $ | 0.73 | $ | 0.76 | ||||||||||
|
Dividend payout ratio
from continuing operations
|
56 | % | 44 | % | 55 | % | 55 | % | 75 | % | ||||||||||
|
Return
from continuing operations on average common equity
|
18.2 | % | 29.8 | % | 23.4 | % | 23.3 | % | 16.0 | % | ||||||||||
|
Ratio
of earnings from continuing operations to fixed charges
|
1.49 | 1.74 | 1.82 | 2.05 | 1.80 | |||||||||||||||
|
At
year-end:
|
||||||||||||||||||||
|
Book value per common
share
|
$ | 4.21 | $ | 4.98 | $ | 5.61 | $ | 5.84 | $ | 6.74 | ||||||||||
|
Market price per
common share
|
12.85 | 16.58 | 17.13 | 12.62 | 14.51 | |||||||||||||||
|
Market price as a
percent of book value
|
305 | % | 333 | % | 305 | % | 216 | % | 215 | % | ||||||||||
|
Total assets
|
$ | 17,116 | $ | 17,633 | $ | 17,872 | $ | 19,676 | $ | 19,773 | ||||||||||
|
Short-term
borrowings
|
- | 187 | 232 | 153 | 55 | |||||||||||||||
|
Transition
and system restoration bonds, including current maturities
|
2,480 | 2,407 | 2,260 | 2,589 | 3,046 | |||||||||||||||
|
Other long-term debt,
including current maturities
|
6,411 | 6,586 | 7,417 | 7,925 | 6,976 | |||||||||||||||
|
Capitalization:
|
||||||||||||||||||||
|
Common stock
equity
|
13 | % | 15 | % | 16 | % | 16 | % | 21 | % | ||||||||||
|
Long-term debt,
including current maturities
|
87 | % | 85 | % | 84 | % | 84 | % | 79 | % | ||||||||||
|
Capitalization,
excluding transition and system restoration bonds:
|
||||||||||||||||||||
|
Common stock
equity
|
17 | % | 19 | % | 20 | % | 20 | % | 27 | % | ||||||||||
|
Long-term
debt, excluding transition and system restoration bonds, including current
maturities
|
83 | % | 81 | % | 80 | % | 80 | % | 73 | % | ||||||||||
|
Capital
expenditures, excluding discontinued operations
|
$ | 719 | $ | 1,121 | $ | 1,011 | $ | 1,053 | $ | 1,148 | ||||||||||
__________
|
|
(1)
|
Net
income for 2005 includes an after-tax extraordinary gain of
$30 million ($0.10 and $0.09 per basic and diluted share,
respectively) recorded in the first quarter reflecting an adjustment to
the extraordinary loss recorded in the last half of 2004 to write down
generation-related regulatory assets as a result of the final orders
issued by the Texas Utility
Commission.
|
|
|
(2)
|
Net
income has been retrospectively adjusted by $5 million,
$5 million, $4 million and $1 million for the years ended
2005, 2006, 2007 and 2008, respectively, to reflect the adoption of new
accounting guidance as of January 1, 2009 for convertible debt instruments
that may be settled in cash upon
conversion.
|
Item 7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations
The following discussion and
analysis should be read in combination with our consolidated financial statements
included in Item 8 herein.
OVERVIEW
Background
We are a
public utility holding company whose indirect wholly owned subsidiaries
include:
|
|
•
|
CenterPoint
Energy Houston Electric, LLC (CenterPoint Houston), which engages in the
electric transmission and distribution business in a 5,000-square mile
area of the Texas Gulf Coast that includes the city of Houston;
and
|
|
|
•
|
CenterPoint
Energy Resources Corp. (CERC Corp. and, together with its subsidiaries,
CERC), which owns and operates natural gas distribution systems in six
states. Subsidiaries of CERC Corp. own interstate natural gas pipelines
and gas gathering systems and provide various ancillary services. A wholly
owned subsidiary of CERC Corp. offers variable and fixed-price physical
natural gas supplies primarily to commercial and industrial customers and
electric and gas utilities.
|
Business
Segments
In this
Management’s Discussion, we discuss our results from continuing operations on a
consolidated basis and individually for each of our business segments. We also
discuss our liquidity, capital resources and certain critical accounting
policies. We are first and foremost an energy delivery company and it is our
intention to remain focused on this segment of the energy business. The results
of our business operations are significantly impacted by weather, customer
growth, economic conditions, cost management, rate proceedings before regulatory
agencies and other actions of the various regulatory agencies to which we are
subject. Our electric transmission and distribution services are subject to rate
regulation and are reported in the Electric Transmission & Distribution
business segment, as are impacts of generation-related stranded costs and other
true-up balances recoverable by the regulated electric utility. Our natural gas
distribution services are also subject to rate regulation and are reported in
the Natural Gas Distribution business segment. A summary of our reportable
business segments as of December 31, 2009 is set forth below:
Electric
Transmission & Distribution
Our
electric transmission and distribution operations provide electric transmission
and distribution services to retail electric providers (REPs) serving
approximately 2.1 million metered customers in a 5,000-square-mile area of
the Texas Gulf Coast that has a population of approximately 5.7 million
people and includes the city of Houston.
On behalf
of REPs, CenterPoint Houston delivers electricity from power plants to
substations, from one substation to another and to retail electric customers in
locations throughout CenterPoint Houston’s certificated service territory. The
Electric Reliability Council of Texas, Inc. (ERCOT) serves as the regional
reliability coordinating council for member electric power systems in Texas.
ERCOT membership is open to consumer groups, investor and municipally-owned
electric utilities, rural electric cooperatives, independent generators, power
marketers and REPs. The ERCOT market represents approximately 85% of the demand
for power in Texas and is one of the nation’s largest power markets.
Transmission and distribution services are provided under tariffs approved by
the Public Utility Commission of Texas (Texas Utility Commission).
Natural
Gas Distribution
CERC owns
and operates our regulated natural gas distribution business (Gas Operations),
which engages in intrastate natural gas sales to, and natural gas transportation
for, approximately 3.2 million residential, commercial and industrial
customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and
Texas.
Competitive
Natural Gas Sales and Services
CERC’s
operations also include non-rate regulated retail and wholesale natural gas
sales to, and transportation services for, commercial and industrial customers
in 18 states in the central and eastern regions of the United
States.
Interstate
Pipelines
CERC’s
interstate pipelines business owns and operates approximately 8,000 miles
of natural gas transmission lines primarily located in Arkansas, Illinois,
Louisiana, Missouri, Oklahoma and Texas. It also owns and operates six natural
gas storage fields with a combined daily deliverability of approximately
1.2 billion cubic feet (Bcf) and a combined working gas capacity of
approximately 59 Bcf. It also owns a 10% interest in an 80 Bcf Bistineau
storage facility located in Bienville Parish, Louisiana, with the remaining
interest owned and operated by Gulf South Pipeline Company, LP. Most storage
operations are in north Louisiana and Oklahoma.
Field
Services
CERC’s
field services business owns and operates approximately 3,700 miles of
gathering pipelines and processing plants that collect, treat and process
natural gas from approximately 140 separate systems located in major producing
fields in Arkansas, Louisiana, Oklahoma and Texas.
Other
Operations
Our other
operations business segment includes office buildings and other real estate used
in our business operations and other corporate operations which support all of
our business operations.
EXECUTIVE
SUMMARY
Factors
Influencing Our Business
We are an
energy delivery company. The majority of our revenues are generated from the
gathering, processing, transportation and sale of natural gas and the
transportation and delivery of electricity by our subsidiaries. We do not own or
operate electric generating facilities or make retail sales to end-use electric
customers. To assess our financial performance, our management primarily
monitors operating income and cash flows from our five business segments. Within
these broader financial measures, we monitor margins, operation and maintenance
expense, interest expense, capital spending and working capital requirements. In
addition to these financial measures we also monitor a number of variables that
management considers important to the operation of our business segments,
including the number of customers, throughput, use per customer, commodity
prices and heating and cooling degree days. We also monitor system reliability,
safety factors and customer satisfaction to gauge our performance.
To the
extent the adverse economic conditions affect our suppliers and customers,
results from our energy delivery businesses may suffer. Reduced
demand and lower energy prices could lead to financial pressure on some of our
customers who operate within the energy industry. Also, adverse economic
conditions, coupled with concerns for protecting the environment, may cause
consumers to use less energy or avoid expansions of their facilities, resulting
in less demand for our services.
Performance
of our Electric Transmission & Distribution and Natural Gas Distribution
business segments is significantly influenced by the number of customers and
energy usage per customer. Weather conditions can have a significant impact on
energy usage, and we compare our results to weather on an adjusted basis. During
2009, we continued to see evidence that customers are seeking to conserve in
their energy consumption, particularly during periods of high energy prices or
in times of economic distress. That conservation can have adverse
effects on our results. In many of our service areas, particularly in the
Houston area and in Minnesota, we have benefited from customer growth that tends
to mitigate the effects of reduced consumption. We anticipate that
this growth will continue despite recent economic downturns, though that growth
may be lower than we have recently experienced in these areas. In
addition, the profitability of these businesses is influenced significantly by
the regulatory treatment we receive from the various state and local regulators
who set our electric and gas distribution rates. In our recent Gas Operations
rate filings, we have sought rate mechanisms that help to decouple our results
from the impacts of
39
weather
and conservation, but such rate mechanisms have not yet been approved in all
jurisdictions. We plan to continue to pursue such decoupling mechanisms in our
rate filings.
Our Field
Services and Interstate Pipelines business segments are currently benefiting
from their proximity to new natural gas producing regions in Texas, Arkansas,
Oklahoma and Louisiana. Our Interstate Pipelines business segment
benefited from new projects placed into service in 2009 on our Carthage to
Perryville line. In our Field Services business segment, strong
drilling activity in the new shale producing regions has helped offset declines
in drilling activity in traditional producing regions due to the effects of the
economic downturn and significantly lower commodity prices in 2009. In
monitoring performance of the segments, we focus on throughput of the pipelines
and gathering systems, and in the case of Field Services, on
well-connects.
Our
Competitive Natural Gas Sales and Services business segment contracts with
customers for transportation, storage and sales of natural gas on an unregulated
basis. Its operations serve customers in the central and eastern
regions of the United States. The segment benefits from favorable
price differentials, either on a geographic basis or on a seasonal basis. While
it utilizes financial derivatives to hedge its exposure to price movements, it
does not engage in speculative or proprietary trading and maintains a low value
at risk level or VaR to avoid significant financial exposures. Lower
commodity prices and low price differentials during 2009 adversely affected
results for this business segment.
The
nature of our businesses requires significant amounts of capital investment, and
we rely on internally generated cash, borrowings under our credit facilities and
issuances of debt and equity in the capital markets to satisfy these capital
needs. We strive to maintain investment grade ratings for our securities in
order to access the capital markets on terms we consider reasonable. Our goal is
to improve our credit ratings over time. A reduction in our ratings
generally would increase our borrowing costs for new issuances of debt, as well
as borrowing costs under our existing revolving credit facilities. Disruptions
in the financial markets, such as occurred in the last half of 2008 and
continued during 2009, can also affect the availability of new capital on terms
we consider attractive. In those circumstances companies like us may not be able
to obtain certain types of external financing or may be required to accept terms
less favorable than they would otherwise accept. For that reason, we seek to
maintain adequate liquidity for our businesses through existing credit
facilities and prudent refinancing of existing debt. For example, we have
negotiated amendments to the financial covenant in our revolving credit facility
to better ensure that adequate debt capacity would be available if needed to
finance restoration costs following major storms. We expect to experience higher
borrowing costs and greater uncertainty in executing capital markets
transactions given the current uncertainties in the financial
markets.
As it did
with many businesses, the sharp decline in stock market values during the latter
part of 2008 had a significant adverse impact on the value of our pension plan
assets. While that impact did not require us to make additional
contributions to the pension plan, it significantly increased the pension
expense we recognized during 2009 and expect to recognize in 2010 for all our
business segments, other than our Electric Transmission & Distribution
business segment, and we may need to make significant cash contributions to our
pension plan subsequent to 2010. Consistent with the regulatory
treatment of such costs, we will defer until our next rate proceeding before the
Texas Utility Commission the amount of pension expense that differs from the
level of pension expense included in our 2007 base rates for our Electric
Transmission & Distribution business segment.
Significant
Events
Hurricane
Ike
CenterPoint
Houston’s electric delivery system suffered substantial damage as a result of
Hurricane Ike, which struck the upper Texas coast in
September 2008.
As is
common with electric utilities serving coastal regions, the poles, towers,
wires, street lights and pole mounted equipment that comprise CenterPoint
Houston’s transmission and distribution system are not covered by property
insurance, but office buildings and warehouses and their contents and
substations are covered by insurance that provides for a maximum deductible of
$10 million. Current estimates are that total losses to property covered by
this insurance were approximately $30 million.
CenterPoint
Houston deferred the uninsured system restoration costs as management believed
it was probable that such costs would be recovered through the regulatory
process. As a result, system restoration costs did not affect CenterPoint
Energy’s or CenterPoint Houston’s reported operating income for 2008 or
2009.
Legislation
enacted by the Texas Legislature in April 2009 authorized the Texas Utility
Commission to conduct proceedings to determine the amount of system restoration
costs and related costs associated with hurricanes or other major storms that
utilities are entitled to recover, and to issue financing orders that would
permit a utility like CenterPoint Houston to recover the distribution portion of
those costs and related carrying costs through the issuance of non-recourse
system restoration bonds similar to the securitization bonds issued
previously. The legislation also allowed such a utility to recover,
or defer for future recovery, the transmission portion of its system restoration
costs through the existing mechanisms established to recover transmission
costs.
Pursuant
to such legislation, CenterPoint Houston filed with the Texas Utility Commission
an application for review and approval for recovery of approximately
$678 million, including approximately $608 million in system
restoration costs identified as of the end of February 2009, plus
$2 million in regulatory expenses, $13 million in certain debt
issuance costs and $55 million in incurred and projected carrying costs
calculated through August 2009. In July 2009, CenterPoint Houston announced
a settlement agreement with the parties to the proceeding. Under that
settlement agreement, CenterPoint Houston was entitled to recover a total of
$663 million in costs relating to Hurricane Ike, along with carrying costs from September 1,
2009 until system restoration bonds were issued. The Texas Utility Commission
issued an order in August 2009 approving CenterPoint Houston’s application and
the settlement agreement and authorizing recovery of $663 million, of which
$643 million was attributable to distribution service and eligible for
securitization and the remaining $20 million was attributable to
transmission service and eligible for recovery through the existing mechanisms
established to recover transmission costs.
In July
2009, CenterPoint Houston filed with the Texas Utility Commission its
application for a financing order to recover the portion of approved costs
related to distribution service through the issuance of system restoration
bonds. In August 2009, the Texas Utility Commission issued a
financing order allowing CenterPoint Houston to securitize $643 million in
distribution service costs plus carrying charges from September 1, 2009
through the date the system restoration bonds were issued, as well as certain
up-front qualified costs capped at approximately $6 million. In
November 2009, CenterPoint Houston issued approximately $665 million of
system restoration bonds through its CenterPoint Energy Restoration Bond
Company, LLC subsidiary with interest rates of 1.833% to 4.243% and final
maturity dates ranging from February 2016 to August 2023. The bonds
will be repaid over time through a charge imposed on customers.
In
accordance with the financing order, CenterPoint Houston also placed a separate
customer credit in effect when the storm restoration bonds were
issued. That credit (ADFIT Credit) is applied to customers’ bills
while the bonds are outstanding to reflect the benefit of accumulated deferred
federal income taxes (ADFIT) associated with the storm restoration costs
(including a carrying charge of 11.075%). The beginning balance of the ADFIT
related to storm restoration costs was approximately $207 million and will
decline over the life of the system restoration bonds as taxes are paid on the
system restoration tariffs. The ADFIT Credit will reduce operating income in
2010 by approximately $24 million.
In
accordance with the orders discussed above, as of December 31, 2009, CenterPoint
Houston has recorded $651 million associated with distribution-related
storm restoration costs as a net regulatory asset and $20 million
associated with transmission-related storm restoration costs, of which
$18 million is recorded in property, plant and equipment and
$2 million of related carrying costs is recorded in regulatory
assets. These amounts reflect carrying costs of $60 million related
to distribution and $2 million related to transmission through December 31,
2009, based on the 11.075% cost of capital approved by the Texas Utility
Commission. The carrying costs have been bifurcated into two components:
(i) return of borrowing costs and (ii) an allowance for earnings on
shareholders’ investment. During the year ended December 31, 2009, the
component representing a return of borrowing costs of $23 million has been
recognized and is included in other income in our Statements of Consolidated
Income. The component representing an allowance for earnings on
shareholders’ investment of $39 million is being deferred and will be
recognized as it is collected through rates.
Gas
Operations also suffered some damage to its system in Houston, Texas and in
other portions of its service territory across Texas and Louisiana. As of
December 31, 2009, Gas Operations has deferred approximately $3 million of
costs related to Hurricane Ike for recovery as part of future natural gas
distribution rate proceedings.
Long-Term
Gas Gathering and Treatment Agreements
In
September 2009, CenterPoint Energy Field Services, Inc. (CEFS), a wholly-owned
natural gas gathering and treating subsidiary of CERC Corp., entered into
long-term agreements with an indirect wholly-owned subsidiary of EnCana
Corporation (EnCana) and an indirect wholly-owned subsidiary of Royal Dutch
Shell plc (Shell) to provide gathering and treating services for their natural
gas production from certain Haynesville Shale and Bossier Shale formations in
Louisiana. CEFS also acquired jointly-owned gathering facilities from EnCana and
Shell in De Soto and Red River parishes in northwest Louisiana. Each
of the agreements includes acreage dedication and volume commitments for which
CEFS has rights to gather Shell’s and EnCana’s natural gas production from the
dedicated areas.
In
connection with the agreements, CEFS commenced gathering and treating services
utilizing the acquired facilities. CEFS is expanding the acquired facilities in
order to gather and treat up to 700 million cubic feet (MMcf) per day of
natural gas. If EnCana or Shell elect, CEFS will further expand the facilities
in order to gather and treat additional future volumes. The
construction necessary to reach the contractual capacity of 700 MMcf per day
includes more than 200 miles of gathering lines, nearly 25,500 horsepower of
compression and over 800 MMcf per day of treating capacity.
CEFS
estimates that the purchase of existing facilities and construction to gather
700 MMcf per day will cost up to $325 million. If EnCana and Shell elect
expansion of the project to gather and process additional future volumes of up
to 1 Bcf per day, CEFS estimates that the expansion would cost as much as
an additional $300 million and EnCana and Shell would provide incremental
volume commitments. Funds for construction are being provided from anticipated
cash flows from operations, lines of credit or proceeds from the sale of debt or
equity securities. As of December 31, 2009, $176 million had
been spent on the project, including the purchase of existing
facilities.
Debt
Financing Transactions
In
January 2009, CenterPoint Houston issued $500 million aggregate principal
amount of general mortgage bonds due in March 2014 with an interest rate of
7.00%. The proceeds from the sale of the bonds were used for general
corporate purposes, including the repayment of outstanding borrowings under
CenterPoint Houston’s revolving credit facility and the money pool, capital
expenditures and storm restoration costs associated with Hurricane
Ike.
In August
2009, Southeast Supply Header, LLC (SESH) closed on a private debt offering in
the amount of $375 million. Also during 2009, CERC Corp. made a
capital contribution to SESH in the amount of
$137 million. Using $186 million of its proceeds from the
debt offering and the capital contribution, SESH repaid the note receivable it
owed to CERC Corp., which note had a principal balance of $323 million at
the time of the repayment. CERC Corp. used the proceeds to repay borrowings
under its credit facility.
In
October 2009, CenterPoint Houston terminated its $600 million 364-day
secured credit facility which had been arranged in November 2008 following
Hurricane Ike.
In
October 2009, the size of CERC Corp.’s revolving credit facility was reduced
from $950 million to $915 million through removal of Lehman Brothers
Bank, FSB (Lehman) as a lender. Prior to its removal, Lehman had a
$35 million commitment to lend. All credit facility loans to
CERC Corp. that were funded by Lehman were repaid in September
2009.
In
October 2009, CERC amended its receivables facility to extend the termination
date to October 8, 2010. Availability under CERC’s 364-day
receivables facility ranges from $150 million to $375 million,
reflecting seasonal changes in receivables balances.
In
January 2010, we purchased $290 million principal amount of pollution
control bonds issued on our behalf at 101% of their principal amount plus
accrued interest pursuant to the mandatory tender provisions of the
bonds.
42
Prior to
the purchase, the pollution control bonds had a fixed rate of interest of
5.125%. The purchase reduces temporary investments and leverage while providing
us with the flexibility to finance future capital needs in the tax-exempt market
through a remarketing of these bonds.
In
January 2010, CERC Corp. redeemed $45 million of its outstanding 6%
convertible subordinated debentures due 2012 at 100% of the principal amount
plus accrued and unpaid interest to the redemption date.
Equity
Financing Transactions
During
the year ended December 31, 2009, we received net proceeds of approximately
$280 million from the issuance of 24.2 million common shares in an
underwritten public offering, net proceeds of $148 million from the
issuance of 14.3 million common shares through a continuous offering
program, proceeds of approximately $57 million from the sale of
approximately 4.9 million common shares to our defined contribution plan
and proceeds of approximately $15 million from the sale of approximately
1.3 million common shares to participants in our enhanced dividend
reinvestment plan.
Asset
Management Agreements
In 2009,
Gas Operations entered into various asset management agreements associated with
its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma
and Texas. Generally, these asset management agreements are contracts
between Gas Operations and an asset manager that are intended to transfer the
working capital obligation and maximize the utilization of the assets. In these
agreements, Gas Operations agreed to release transportation and storage capacity
to other parties to manage gas storage, supply and delivery arrangements for Gas
Operations and to use the released capacity for other purposes when it is not
needed for Gas Operations. Gas Operations is compensated by the asset
manager through payments made over the life of the agreements based in part on
the results of the asset optimization. Gas Operations has received
approval from the state regulatory commissions in Arkansas, Louisiana,
Mississippi and Oklahoma to retain a share of the asset management agreement
proceeds, although the percentage of payments to be retained by Gas Operations
varies based on the jurisdiction, with the majority of the payments to benefit
customers. The agreements have varying terms, the longest of which expires in
2016.
CERTAIN
FACTORS AFFECTING FUTURE EARNINGS
Our past
earnings and results of operations are not necessarily indicative of our future
earnings and results of operations. The magnitude of our future earnings and
results of our operations will depend on or be affected by numerous factors
including:
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•
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the
resolution of the true-up proceedings, including, in particular, the
results of appeals to the Texas Supreme Court regarding rulings obtained
to date;
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•
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state
and federal legislative and regulatory actions or developments, including
deregulation, re-regulation, health care reform, and changes in or
application of laws or regulations applicable to the various aspects of
our business;
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•
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state
and federal legislative and regulatory actions, developments or
regulations relating to the environment, including those related to global
climate change;
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•
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timely
and appropriate legislative and regulatory actions allowing securitization
or other recovery of costs associated with any future hurricanes or
natural disasters;
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•
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timely
and appropriate rate actions and increases, allowing recovery of costs and
a reasonable return on investment;
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•
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cost
overruns on major capital projects that cannot be recouped in
prices;
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•
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industrial,
commercial and residential growth in our service territory and changes in
market demand and demographic
patterns;
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•
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the
timing and extent of changes in commodity prices, particularly natural gas
and natural gas liquids;
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•
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the
timing and extent of changes in the supply of natural gas, including
supplies available for gathering by our field services
business;
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•
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the
timing and extent of changes in natural gas basis
differentials;
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•
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weather
variations and other natural
phenomena;
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•
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changes
in interest rates or rates of
inflation;
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•
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commercial
bank and financial market conditions, our access to capital, the cost of
such capital, and the results of our financing and refinancing efforts,
including availability of funds in the debt capital
markets;
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•
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actions
by rating agencies;
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•
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effectiveness
of our risk management activities;
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•
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inability
of various counterparties to meet their obligations to
us;
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•
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non-payment
for our services due to financial distress of our
customers;
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•
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the
ability of RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc.
and Reliant Resources, Inc.) and its subsidiaries to satisfy their
obligations to us, including indemnity obligations, or in connection with
the contractual arrangements pursuant to which we are their
guarantor;
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•
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the
ability of REPs that are subsidiaries of NRG Retail LLC and TXU Energy
Retail Company LLC (TXU Energy), which are CenterPoint Houston’s two
largest customers, to satisfy their obligations to us and our
subsidiaries;
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•
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the
outcome of litigation brought by or against
us;
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•
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our
ability to control costs;
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•
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the
investment performance of our pension and postretirement benefit
plans;
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•
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our
potential business strategies, including acquisitions or dispositions of
assets or businesses, which we cannot assure will be completed or will
have the anticipated benefits to
us;
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•
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acquisition
and merger activities involving us or our competitors;
and
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•
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other
factors we discuss under "Risk Factors" in Item 1A of this report and
in other reports we file from time to time with the Securities and
Exchange Commission.
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CONSOLIDATED
RESULTS OF OPERATIONS
All
dollar amounts in the tables that follow are in millions, except for per share
amounts.
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Year
Ended December 31,
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2007
|
2008
|
2009
|
||||||||||
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Revenues
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$ | 9,623 | $ | 11,322 | $ | 8,281 | ||||||
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Expenses
|
8,438 | 10,049 | 7,157 | |||||||||
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Operating
Income
|
1,185 | 1,273 | 1,124 | |||||||||
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Gain
(Loss) on Marketable Securities
|
(114 | ) | (139 | ) | 82 | |||||||
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Gain
(Loss) on Indexed Debt Securities
|
111 | 128 | (68 | ) | ||||||||
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Interest
and Other Finance Charges
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(509 | ) | (468 | ) | (513 | ) | ||||||
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Interest
on Transition and System Restoration Bonds
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(123 | ) | (136 | ) | (131 | ) | ||||||
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Distribution
from AOL Time Warner Litigation Settlement
|
32 | - | 3 | |||||||||
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Additional
Distribution to ZENS Holders
|
(27 | ) | - | (3 | ) | |||||||
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Equity
in Earnings of Unconsolidated Affiliates
|
16 | 51 | 15 | |||||||||
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Other
Income, net
|
17 | 14 | 39 | |||||||||
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Income
Before Income Taxes
|
588 | 723 | 548 | |||||||||
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Income
Tax Expense
|
(193 | ) | (277 | ) | (176 | ) | ||||||
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Net
Income
|
$ | 395 | $ | 446 | $ | 372 | ||||||
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Basic
Earnings Per Share
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$ | 1.23 | $ | 1.32 | $ | 1.02 | ||||||
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Diluted
Earnings Per Share
|
$ | 1.15 | $ | 1.30 | $ | 1.01 | ||||||
2009
Compared to 2008
Net Income. We
reported net income of $372 million ($1.01 per diluted share) for 2009
compared to $446 million ($1.30 per diluted share) for the same period
in 2008. The decrease in net income of $74 million was primarily due to a
$149 million decrease in operating income, a $45 million increase in
interest expense due primarily to higher interest rates and higher levels of
debt during 2009, excluding transition and system restoration bond-related
interest expense, a $36 million decrease in equity in earnings of
unconsolidated affiliates and a $196 million decrease in the gain on our
indexed debt securities. These decreases in net income were partially
offset by a $101 million decrease in income tax expense, a
$221 million increase in the gain on our marketable securities,
$23 million of carrying costs related to Hurricane Ike restoration costs
included in Other Income, net and a $5 million decrease in interest expense
on transition and system restoration bonds.
Income Tax Expense. Our
2009 effective tax rate of 32.1% differed from the 2008 effective tax rate of
38.4% primarily due to the settlement of our federal income tax return
examinations for tax years 2004 and 2005 and a reduction in state income taxes
related to adjustments in prior years’ state estimates. For more
information, see Note 9 to our consolidated financial statements.
2008
Compared to 2007
Net Income. We
reported net income of $446 million ($1.30 per diluted share) for 2008
compared to $395 million ($1.15 per diluted share) for the same period
in 2007. The increase in net income of $51 million was primarily due to an
$88 million increase in operating income, a $41 million decrease in
interest expense, excluding transition bond-related interest expense, a
$35 million increase in equity in earnings of unconsolidated affiliates
related primarily to SESH and a $17 million increase in the gain on our
indexed debt securities. These increases in net income were partially
offset by an $84 million increase in income tax expense, a $25 million
increase in the loss on our Time Warner investment and a $13 million
increase in interest expense on transition bonds.
Income Tax
Expense. Our 2008 effective tax rate of 38.4% differed from
the 2007 effective tax rate of 32.8% primarily as a result of revisions to the
Texas State Franchise Tax Law (Texas margin tax), which was reported as an
operating expense prior to 2008 and is now being reported as an income tax for
CenterPoint Houston, and a Texas state tax examination in 2007.
RESULTS
OF OPERATIONS BY BUSINESS SEGMENT
The
following table presents operating income (in millions) for each of our business
segments for 2007, 2008 and 2009. Included in revenues are intersegment sales.
We account for intersegment sales as if the sales were to third parties, that
is, at current market prices.
Operating
Income (Loss) by Business Segment
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Year
Ended December 31,
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2007
|
2008
|
2009
|
||||||||||
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Electric
Transmission & Distribution
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$ | 561 | $ | 545 | $ | 545 | ||||||
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Natural
Gas Distribution
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218 | 215 | 204 | |||||||||
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Competitive
Natural Gas Sales and Services
|
75 | 62 | 21 | |||||||||
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Interstate
Pipelines
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237 | 293 | 256 | |||||||||
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Field
Services
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99 | 147 | 94 | |||||||||
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Other
Operations
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(5 | ) | 11 | 4 | ||||||||
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Total
Consolidated Operating Income
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$ | 1,185 | $ | 1,273 | $ | 1,124 | ||||||
Electric
Transmission & Distribution
The
following tables provide summary data of our Electric Transmission &
Distribution business segment, CenterPoint Houston, for 2007, 2008 and 2009 (in
millions, except throughput and customer data):
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Year
Ended December 31,
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2007
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2008
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2009
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Revenues:
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Electric
transmission and distribution utility
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$ | 1,560 | $ | 1,593 | $ | 1,673 | ||||||
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Transition
and system restoration bond companies
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277 | 323 | 340 | |||||||||
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Total
revenues
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1,837 | 1,916 | 2,013 | |||||||||
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Expenses:
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||||||||||||
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Operation
and maintenance, excluding transition and system
restoration
bond companies
|
652 | 703 | 774 | |||||||||
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Depreciation
and amortization, excluding transition and system
restoration
bond companies
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243 | 277 | 277 | |||||||||
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Taxes
other than income taxes
|
223 | 201 | 208 | |||||||||
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Transition
and system restoration bond companies
|
158 | 190 | 209 | |||||||||
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Total
expenses
|
1,276 | 1,371 | 1,468 | |||||||||
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Operating
Income
|
$ | 561 | $ | 545 | $ | 545 | ||||||
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Operating
Income:
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||||||||||||
|
Electric
transmission and distribution operations
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$ | 400 | $ | 407 | $ | 414 | ||||||
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Competition
transition charge
|
42 | 5 | - | |||||||||
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Transition
and system restoration bond companies (1)
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119 | 133 | 131 | |||||||||
|
Total
segment operating income
|
$ | 561 | $ | 545 | $ | 545 | ||||||
|
Throughput
(in gigawatt-hours (GWh)):
|
||||||||||||
|
Residential
|
23,999 | 24,258 | 24,815 | |||||||||
|
Total
|
76,291 | 74,840 | 74,579 | |||||||||
|
Number
of metered customers at end of period:
|
||||||||||||
|
Residential
|
1,793,600 | 1,821,267 | 1,849,019 | |||||||||
|
Total
|
2,034,074 | 2,064,854 | 2,094,210 | |||||||||
__________
|
|
(1)
|
Represents
the amount necessary to pay interest on the transition and system
restoration bonds.
|
2009 Compared to
2008. Our Electric Transmission & Distribution business
segment reported operating income of $545 million for 2009, consisting of
$414 million from our regulated electric transmission and distribution
utility operations (TDU) and $131 million related to transition and system
restoration bond companies. For 2008, operating income totaled
$545 million, consisting of $407 million from the TDU, exclusive of an
additional $5 million from the competition transition charge (CTC), and
$133 million related to transition bond companies. Revenues for the TDU
increased due to higher transmission-related revenues ($50 million), in
part reflecting the impact of a
46
transmission
rate increase implemented in November 2008, the impact of Hurricane Ike in 2008
($17 million), revenues from implementation of AMS ($33 million) and
higher revenues due to customer growth ($17 million) from the addition of
over 29,000 new customers, partially offset by declines in energy
demand ($27 million). Operation and maintenance expenses
increased $71 million primarily due to higher transmission costs billed by
transmission providers ($18 million), increased operating and maintenance
expenses that were postponed in 2008 as a result of Hurricane Ike restoration
efforts ($10 million), higher pension and other employee benefit costs
($10 million), expenses related to AMS ($14 million) and a gain on a
land sale in 2008 ($9 million). Increased depreciation expense related to
increased investment in AMS ($7 million) was offset by other declines in
depreciation and amortization, primarily due to asset retirements. Taxes other
than income taxes increased $7 million primarily as a result of a refund in
2008 of prior years’ state franchise taxes ($5 million). Changes in pension
expense over our 2007 base year amount are being deferred until our next general
rate case pursuant to Texas law.
2008 Compared to
2007. Our Electric Transmission & Distribution business
segment reported operating income of $545 million for 2008, consisting of
$407 million from the TDU, exclusive of an additional $5 million from
the CTC, and $133 million related to transition bond companies. For
2007, operating income totaled $561 million, consisting of
$400 million from the TDU, exclusive of an additional $42 million from
the CTC, and $119 million related to transition bond companies. Revenues
for the TDU increased in 2008 due to customer growth, with over
30,000 metered customers added ($23 million), increased usage
($15 million) in part caused by favorable weather experienced, increased
transmission-related revenues ($21 million) and increased revenues from
ancillary services ($5 million), partially offset by reduced revenues due
to Hurricane Ike ($17 million) and the settlement of the final fuel
reconciliation in 2007 ($5 million). Operation and maintenance expense
increased primarily due to higher transmission costs ($43 million), the
settlement of the final fuel reconciliation in 2007 ($13 million) and
increased support services ($13 million), partially offset by a gain on
sale of land ($9 million) and normal operating and maintenance expenses
that were postponed as a result of Hurricane Ike restoration efforts
($10 million). Depreciation and amortization increased $34 million
primarily due to amounts related to the CTC ($30 million), which were
offset by similar amounts in revenues. Taxes other than income taxes declined
$21 million primarily as a result of the Texas margin tax being classified
as an income tax for financial reporting purposes in 2008 ($19 million) and
a refund of prior years’ state franchise taxes ($5 million).
Natural
Gas Distribution
The
following table provides summary data of our Natural Gas Distribution business
segment for 2007, 2008 and 2009 (in millions, except throughput and customer
data):
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
Revenues
|
$ | 3,759 | $ | 4,226 | $ | 3,384 | ||||||
|
Expenses:
|
||||||||||||
|
Natural
gas
|
2,683 | 3,124 | 2,251 | |||||||||
|
Operation
and maintenance
|
579 | 589 | 639 | |||||||||
|
Depreciation
and amortization
|
155 | 157 | 161 | |||||||||
|
Taxes
other than income taxes
|
124 | 141 | 129 | |||||||||
|
Total
expenses
|
3,541 | 4,011 | 3,180 | |||||||||
|
Operating
Income
|
$ | 218 | $ | 215 | $ | 204 | ||||||
|
Throughput
(in Bcf):
|
||||||||||||
|
Residential
|
172 | 175 | 173 | |||||||||
|
Commercial
and industrial
|
232 | 236 | 233 | |||||||||
|
Total
Throughput
|
404 | 411 | 406 | |||||||||
|
Number
of customers at end of period:
|
||||||||||||
|
Residential
|
2,961,110 | 2,987,222 | 3,002,114 | |||||||||
|
Commercial
and industrial
|
249,877 | 248,476 | 244,101 | |||||||||
|
Total
|
3,210,987 | 3,235,698 | 3,246,215 | |||||||||
2009 Compared to
2008. Our Natural Gas Distribution business segment reported
operating income of $204 million for 2009 compared to $215 million for
2008. Operating income declined ($11 million) primarily as a result of
increased pension expense ($37 million) and higher labor and other benefit
costs ($16 million), partially
47
offset by
increased revenues from rate increases ($36 million) and lower bad debt
expense ($15 million). Revenues related to both energy-efficiency costs and
gross receipts taxes are substantially offset by the related expenses.
Depreciation and amortization expense increased $4 million primarily due to
higher plant balances. Taxes other than income taxes, net of the
decrease in gross receipts taxes ($16 million), increased $4 million
also primarily due to higher plant balances.
2008 Compared to
2007. Our Natural Gas Distribution business segment reported
operating income of $215 million for 2008 compared to $218 million for
2007. Operating income declined in 2008 due to a combination of
non-weather-related usage ($13 million), due in part to higher gas prices,
higher customer-related and support services costs ($9 million), higher bad
debts and collection costs ($4 million), increased costs of materials and
supplies ($4 million), and an increase in depreciation and amortization and
taxes other than income taxes ($3 million) resulting from increased
investment in property, plant and equipment. The adverse impacts on operating
income were partially offset by the net impact of rate increases
($11 million), lower labor and benefits costs ($14 million), and
customer growth from the addition of approximately 25,000 customers in 2008
($6 million).
Competitive
Natural Gas Sales and Services
The
following table provides summary data of our Competitive Natural Gas Sales and
Services business segment for 2007, 2008 and 2009 (in millions, except
throughput and customer data):
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
Revenues
|
$ | 3,579 | $ | 4,528 | $ | 2,230 | ||||||
|
Expenses:
|
||||||||||||
|
Natural
gas
|
3,467 | 4,423 | 2,165 | |||||||||
|
Operation
and maintenance
|
31 | 39 | 39 | |||||||||
|
Depreciation
and amortization
|
5 | 3 | 4 | |||||||||
|
Taxes
other than income taxes
|
1 | 1 | 1 | |||||||||
|
Total
expenses
|
3,504 | 4,466 | 2,209 | |||||||||
|
Operating
Income
|
$ | 75 | $ | 62 | $ | 21 | ||||||
|
Throughput
(in Bcf)
|
522 | 528 | 504 | |||||||||
|
Number
of customers at end of period
|
7,139 | 9,771 | 11,168 | |||||||||
2009 Compared to 2008.
Our Competitive Natural Gas Sales and Services business
segment reported operating income of $21 million for 2009 compared to
$62 million for 2008. The decrease in operating income of
$41 million was due to the unfavorable impact of the mark-to-market
valuation for non-trading financial derivatives for 2009 of $23 million
versus a favorable impact of $13 million for the same period in
2008. A further $28 million decrease in margin is attributable
to reduced basis spreads on pipeline transport opportunities and an absence of
summer storage spreads. These decreases in operating income were partially
offset by a $6 million write-down of natural gas inventory to the lower of
cost or market for 2009 compared to a $30 million write-down in the same
period last year. Our Competitive Natural Gas Sales and Services
business segment purchases and stores natural gas to meet certain future sales
requirements and enters into derivative contracts to hedge the economic value of
the future sales.
2008 Compared to 2007.
Our Competitive Natural Gas Sales and Services business
segment reported operating income of $62 million for the year ended
December 31, 2008 compared to $75 million for the year ended December 31,
2007. The decrease in operating income in 2008 of $13 million
primarily resulted from lower gains on sales of gas from previously written down
inventory ($24 million) and higher operation and maintenance costs
($6 million), which were partially offset by improved margin as basis and
summer/winter spreads increased ($12 million). In addition, 2008 included a
gain from mark-to-market accounting ($13 million) and a write-down of
natural gas inventory to the lower of average cost or market ($30 million),
compared to a charge to income from mark-to-market accounting for non-trading
derivatives ($10 million) and a write-down of natural gas inventory to the
lower of average cost or market ($11 million) for 2007.
Interstate
Pipelines
The
following table provides summary data of our Interstate Pipelines business
segment for 2007, 2008 and 2009 (in millions, except throughput
data):
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
Revenues
|
$ | 500 | $ | 650 | $ | 598 | ||||||
|
Expenses:
|
||||||||||||
|
Natural
gas
|
83 | 155 | 97 | |||||||||
|
Operation
and maintenance
|
125 | 133 | 166 | |||||||||
|
Depreciation
and amortization
|
44 | 46 | 48 | |||||||||
|
Taxes
other than income taxes
|
11 | 23 | 31 | |||||||||
|
Total
expenses
|
263 | 357 | 342 | |||||||||
|
Operating
Income
|
$ | 237 | $ | 293 | $ | 256 | ||||||
|
Transportation
throughput (in Bcf)
|
1,216 | 1,538 | 1,592 | |||||||||
2009 Compared to
2008. Our Interstate Pipeline business segment reported
operating income of $256 million for 2009 compared to $293 million for
2008. Margins (revenues less natural gas costs) increased $6 million
primarily due to the Carthage to Perryville pipeline ($28 million) and new
contracts with power generation customers ($20 million), partially offset
by reduced other transportation margins and ancillary services
($42 million) primarily due to the decline in commodity prices from the
significantly higher levels in 2008. Operations and maintenance
expenses increased due to a gain on the sale of two storage development projects
in 2008 ($18 million) and costs associated with incremental facilities
($12 million) and increased pension expenses
($9 million). These expenses were partially offset by a
write-down associated with pipeline assets removed from service in the third
quarter of 2008 ($7 million). Depreciation and amortization
expenses increased $2 million and taxes other than income taxes increased
by $8 million, $2 million of which was due to 2008 tax
refunds.
2008 Compared to
2007. Our Interstate Pipeline business segment reported
operating income of $293 million for 2008 compared to $237 million for
2007. The increase in operating income in 2008 was primarily driven by increased
margins (revenues less natural gas costs) on the Carthage to Perryville pipeline
that went into service in May 2007 ($51 million), increased transportation
and ancillary services ($27 million), and a gain on the sale of two storage
development projects ($18 million). These increases were partially offset
by higher operation and maintenance expenses ($19 million), a write-down
associated with pipeline assets removed from service ($7 million),
increased depreciation expense ($2 million), and higher taxes other than
income taxes ($12 million), largely due to tax refunds in
2007.
Equity Earnings. In addition,
this business segment recorded equity income of $6 million,
$36 million and $7 million in the years ended December 31, 2007, 2008
and 2009, respectively, from its 50% interest in SESH, a jointly-owned pipeline.
The 2007 and 2008 year-end results include $6 million and $33 million
of pre-operating allowance for funds used during construction, respectively. The
2009 results include a non-cash pre-tax charge of $16 million to reflect
SESH’s decision to discontinue the use of guidance for accounting for regulated
operations, which was partially offset by the receipt of a one-time payment
related to the construction of the pipeline and a reduction in estimated
property taxes, of which our 50% share was $5 million. Excluding the effect
of these adjustments, equity earnings from normal operations was $3 million
and $18 million in 2008 and 2009, respectively. These amounts
are included in Equity in Earnings of Unconsolidated Affiliates under the Other
Income (Expense) caption.
Field
Services
The
following table provides summary data of our Field Services business segment for
2007, 2008 and 2009 (in millions, except throughput data):
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
Revenues
|
$ | 175 | $ | 252 | $ | 241 | ||||||
|
Expenses:
|
||||||||||||
|
Natural
gas
|
(4 | ) | 21 | 51 | ||||||||
|
Operation
and maintenance
|
66 | 69 | 77 | |||||||||
|
Depreciation
and amortization
|
11 | 12 | 15 | |||||||||
|
Taxes
other than income taxes
|
3 | 3 | 4 | |||||||||
|
Total
expenses
|
76 | 105 | 147 | |||||||||
|
Operating
Income
|
$ | 99 | $ | 147 | $ | 94 | ||||||
|
Gathering
throughput (in Bcf)
|
398 | 421 | 426 | |||||||||
2009 Compared to
2008. Our Field Services business segment reported operating
income of $94 million for 2009 compared to $147 million for 2008.
Operating margin from new projects and core gathering services increased
approximately $24 million for 2009 when compared to the same period in 2008
primarily due to continued development in the shale plays. This
increase was offset primarily by the effect of a decline in commodity prices of
approximately $54 million from the significantly higher prices experienced
in 2008. Operating income for 2009 also included higher costs
associated with incremental facilities ($4 million) and increased pension
cost ($2 million). Operating income for 2008 benefited from a
one-time gain ($11 million) related to a settlement and contract buyout of
one of our customers and a gain on sale of assets
($6 million).
2008 Compared to
2007. Our Field Services business segment reported operating
income of $147 million for 2008 compared to $99 million for 2007. The
increase in operating income of $48 million resulted from higher margins
(revenue less natural gas costs) from gas gathering, ancillary services and
higher commodity prices ($34 million) and a one-time gain related to a
settlement and contract buyout of one of our customers
($11 million). Operating expenses increased from 2007 to 2008
due to higher expenses associated with new assets and general cost increases,
partially offset by a gain related to the sale of assets in 2008
($6 million).
Equity Earnings. In addition,
this business segment recorded equity income of $10 million,
$15 million and $8 million for the years ended December 31, 2007,
2008 and 2009, respectively, from its 50% interest in a jointly-owned gas
processing plant. The decrease is driven by a decrease in natural gas liquid
prices. These amounts are included in Equity in earnings of unconsolidated
affiliates under the Other Income (Expense) caption.
Other
Operations
The
following table provides summary data for our Other Operations business segment
for 2007, 2008 and 2009 (in millions):
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
Revenues
|
$ | 10 | $ | 11 | $ | 11 | ||||||
|
Expenses
|
15 | – | 7 | |||||||||
|
Operating
Income (Loss)
|
$ | (5 | ) | $ | 11 | $ | 4 | |||||
2009 Compared to
2008. Our Other Operations business segment’s operating income
in 2009 compared to 2008 decreased by $7 million primarily as a result of
an increase in depreciation and amortization expense ($4 million) and an
increase in franchise taxes ($3 million).
2008 Compared to
2007. Our Other Operations business segment’s operating income
in 2008 compared to 2007 increased by $16 million primarily as a result of
a decrease in franchise taxes ($7 million) and a decrease in benefits
accruals ($4 million).
LIQUIDITY
AND CAPITAL RESOURCES
Historical
Cash Flows
The net
cash provided by (used in) operating, investing and financing activities for
2007, 2008 and 2009 is as follows (in millions):
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
Cash
provided by (used in):
|
||||||||||||
|
Operating
activities
|
$ | 774 | $ | 851 | $ | 1,841 | ||||||
|
Investing
activities
|
(1,300 | ) | (1,368 | ) | (896 | ) | ||||||
|
Financing
activities
|
528 | 555 | (372 | ) | ||||||||
Cash
Provided by Operating Activities
Net cash
provided by operating activities in 2009 increased $990 million compared to
2008 primarily due to decreased cash used in net regulatory assets and
liabilities primarily related to Hurricane Ike restoration costs in 2008
($366 million), decreased cash used in net margin deposits
($298 million), decreased cash used in gas storage inventory
($246 million) and increased cash provided by net accounts
receivable/payable ($41 million).
Net cash
provided by operating activities in 2008 increased $77 million compared to
2007 primarily due to decreased tax payments/increased tax refunds
($289 million), increased net accounts receivable/payable
($190 million), increased fuel cost recovery ($138 million) and
increased pre-tax income ($131 million). These increases were partially
offset by increased net regulatory assets and liabilities ($447 million)
and increased net margin deposits ($247 million).
Cash
Used in Investing Activities
Net cash
used in investing activities decreased $472 million in 2009 compared to
2008 due to decreased notes receivable from unconsolidated affiliates of
$498 million, decreased investment in unconsolidated affiliates of
$91 million and decreased restricted cash of transition bond companies of
$37 million, offset by increased capital expenditures of $140 million
primarily related to our Field Services business segment.
Net cash
used in investing activities increased $68 million in 2008 compared to 2007
due to increased investment in unconsolidated affiliates of $167 million,
primarily related to the SESH pipeline project, which was partially offset by
decreased capital expenditures of $94 million.
Cash
Provided by (Used in) Financing Activities
Net cash
used in financing activities in 2009 increased $927 million compared to
2008 primarily due to decreased borrowings under revolving credit facilities
($2.6 billion), and decreased short-term borrowings ($19 million),
which were partially offset by decreased repayments of long-term debt
($1.2 billion), increased proceeds from the issuance of common stock
($424 million) and increased proceeds from the issuance of long-term debt
($77 million).
Net cash
provided by financing activities in 2008 increased $27 million compared to
2007 primarily due to increased borrowings under revolving credit facilities
($779 million) and increased proceeds from long-term debt
($188 million), which were partially offset by increased repayments of
long-term debt ($825 million) and decreased short-term borrowings
($124 million).
Future
Sources and Uses of Cash
Our
liquidity and capital requirements are affected primarily by our results of
operations, capital expenditures, debt service requirements, tax payments,
working capital needs, various regulatory actions and appeals relating to such
regulatory actions. Our principal anticipated cash requirements for 2010 include
the following:
|
|
•
|
approximately
$1.2 billion of capital
requirements;
|
|
|
•
|
maturing
long-term debt aggregating approximately
$206 million;
|
|
|
•
|
$290 million
for our January 2010 purchase of pollution control bonds issued on our
behalf;
|
|
|
•
|
$241 million
of scheduled principal payments on transition and system restoration
bonds;
|
|
|
•
|
$45 million
for our January 2010 redemption of debentures;
and
|
|
|
•
|
dividend
payments on CenterPoint Energy common stock and interest payments on
debt.
|
We expect
that borrowings under our credit facilities and anticipated cash flows from
operations will be sufficient to meet our anticipated cash needs in 2010. Cash
needs or discretionary financing or refinancing may result in the issuance of
equity or debt securities in the capital markets or the arrangement of
additional credit facilities. Issuances of equity or debt in the capital markets
and additional credit facilities may not, however, be available to us on
acceptable terms.
The
following table sets forth our capital expenditures for 2009 and estimates of
our capital requirements for 2010 through 2014 (in millions):
|
2009
|
2010
|
2011
|
2012
|
2013
|
2014
|
|||||||||||||||||||
|
Electric
Transmission & Distribution (1)
|
$ | 428 | $ | 557 | $ | 563 | $ | 488 | $ | 503 | $ | 484 | ||||||||||||
|
Natural
Gas Distribution
|
165 | 210 | 237 | 241 | 259 | 248 | ||||||||||||||||||
|
Competitive
Natural Gas Sales and Services
|
2 | 6 | 4 | 16 | 5 | 5 | ||||||||||||||||||
|
Interstate
Pipelines
|
176 | 171 | 192 | 245 | 164 | 94 | ||||||||||||||||||
|
Field
Services
|
348 | 226 | 163 | 126 | 95 | 85 | ||||||||||||||||||
|
Other
Operations
|
29 | 38 | 59 | 40 | 30 | 30 | ||||||||||||||||||
|
Total
|
$ | 1,148 | $ | 1,208 | $ | 1,218 | $ | 1,156 | $ | 1,056 | $ | 946 | ||||||||||||
|
|
(1)
|
Includes
expenditures of $94 million in 2009 and capital requirements of
$181 million, $172 million, $49 million, $38 million
and $34 million in 2010 through 2014, respectively, related to AMS
and Intelligent Grid, net of a $200 million grant by the U.S.
Department of Energy (DOE). The award is contingent on
successful completion of negotiations with the
DOE.
|
The
following table sets forth estimates of our contractual obligations, including
payments due by period (in millions):
|
Contractual
Obligations
|
Total
|
2010
|
2011-2012 | 2013-2014 |
2015
and
thereafter
|
|||||||||||||||
|
Transition
and system restoration bond debt
|
$ | 3,046 | $ | 241 | $ | 590 | $ | 565 | $ | 1,650 | ||||||||||
|
Other
long-term debt(1)
|
7,668 | 541 | 615 | 2,171 | 4,341 | |||||||||||||||
|
Interest
payments - transition and system
restoration
bond debt(2)
|
834 | 135 | 245 | 187 | 267 | |||||||||||||||
|
Interest
payments - other long-term debt(2)
|
3,919 | 433 | 791 | 608 | 2,087 | |||||||||||||||
|
Short-term
borrowings
|
55 | 55 | - | - | - | |||||||||||||||
|
Capital
leases
|
1 | - | - | - | 1 | |||||||||||||||
|
Operating
leases(3)
|
51 | 12 | 22 | 10 | 7 | |||||||||||||||
|
Benefit
obligations(4)
|
- | - | - | - | - | |||||||||||||||
|
Purchase
obligations(5)
|
9 | 9 | - | - | - | |||||||||||||||
|
Non-trading
derivative liabilities
|
93 | 51 | 42 | - | - | |||||||||||||||
|
Other
commodity commitments(6)
|
2,558 | 439 | 917 | 659 | 543 | |||||||||||||||
|
Income
taxes(7)
|
- | - | - | - | - | |||||||||||||||
|
Other
|
25 | 7 | 12 | 6 | - | |||||||||||||||
|
Total
contractual cash obligations
|
$ | 18,259 | $ | 1,923 | $ | 3,234 | $ | 4,206 | $ | 8,896 | ||||||||||
|
|
(1)
|
ZENS
obligations are included in the 2015 and thereafter column at their
contingent principal amount payable in 2029 of
$814 million. These obligations are exchangeable for cash
at any time at the option of the holders for 95% of the current value of
the reference shares attributable to each ZENS ($300 million at
December 31, 2009), as discussed in Note 6 to our consolidated financial
statements.
|
|
|
(2)
|
We
calculated estimated interest payments for long-term debt as follows: for
fixed-rate debt and term debt, we calculated interest based on the
applicable rates and payment dates; for variable-rate debt and/or non-term
debt, we used interest rates in place as of December 31, 2009. We
typically expect to settle such interest payments with cash flows from
operations and short-term
borrowings.
|
|
|
(3)
|
For
a discussion of operating leases, please read Note 10(c) to our
consolidated financial statements.
|
|
|
(4)
|
Material
contributions to our qualified pension plan are not expected in 2010.
However, we expect to contribute approximately $9 million and
$19 million, respectively, to our non-qualified pension and
postretirement benefits plans in
2010.
|
|
|
(5)
|
Represents
capital commitments for material in connection with our Interstate
Pipelines business segment.
|
|
|
(6)
|
For
a discussion of other commodity commitments, please read Note 10(a) to our
consolidated financial statements.
|
|
|
(7)
|
As
of December 31, 2009, the liability for uncertain income tax
positions was $187 million. However, due to the high degree of
uncertainty regarding the timing of potential future cash flows associated
with these liabilities, we are unable to make a reasonably reliable
estimate of the amount and period in which any such liabilities might be
paid.
|
Off-Balance Sheet
Arrangements. Other than operating leases and the guaranties described
below, we have no off-balance sheet arrangements.
Prior to
the distribution of our ownership in RRI Energy, Inc. (RRI) (formerly known as
Reliant Energy, Inc. and Reliant Resources, Inc.) to our shareholders, CERC had
guaranteed certain contractual obligations of what became RRI’s trading
subsidiary. When the companies separated, RRI agreed to secure CERC
against obligations under the guaranties RRI had been unable to extinguish by
the time of separation. Pursuant to such agreement, as amended in December
2007, RRI has agreed to provide to CERC cash or letters of credit
as security against CERC’s obligations under its remaining guaranties for
demand charges under certain gas purchase and transportation agreements if and
to the extent changes in market conditions expose CERC to a risk of loss on
those guaranties. As of December 31, 2009, RRI was not required to provide
security to CERC. If RRI should fail to perform the contractual
obligations,
53
CERC
could have to honor its guarantee and, in such event, collateral provided as
security may be insufficient to satisfy CERC’s obligations.
Debt Financing
Transactions. In January 2009, CenterPoint Houston issued
$500 million aggregate principal amount of general mortgage bonds due in
March 2014 with an interest rate of 7.00%. The proceeds from the sale
of the bonds were used for general corporate purposes, including the repayment
of outstanding borrowings under CenterPoint Houston’s revolving credit facility
and the money pool, capital expenditures and storm restoration costs associated
with Hurricane Ike.
In August
2009, SESH closed on a private debt offering in the amount of
$375 million. Also during 2009, CERC Corp. made a capital
contribution to SESH in the amount of $137 million. Using
$186 million of its proceeds from the debt offering and the capital
contribution, SESH repaid the note receivable it owed to CERC Corp., which note
had a principal balance of $323 million at the time of the repayment. CERC
Corp. used the proceeds to repay borrowings under its credit
facility.
In
January 2010, we purchased $290 million principal amount of pollution
control bonds issued on our behalf at 101% of their principal amount plus
accrued interest pursuant to the mandatory tender provisions of the bonds. Prior
to the purchase, the pollution control bonds had a fixed rate of interest of
5.125%. The purchase reduces temporary investments and leverage while providing
us with the flexibility to finance future capital needs in the tax-exempt market
through a remarketing of these bonds.
In
January 2010, CERC Corp. redeemed $45 million of its outstanding 6%
convertible subordinated debentures due 2012 at 100% of the principal amount
plus accrued and unpaid interest to the redemption date.
System Restoration
Bonds. In
November 2009, CenterPoint Houston issued approximately $665 million of
system restoration bonds through its CenterPoint Energy Restoration Bond
Company, LLC subsidiary with interest rates of 1.833% to 4.243% and final
maturity dates ranging from February 2016 to August 2023. The bonds
will be repaid over time through a charge imposed on customers.
Equity Financing
Transactions. During the year ended December 31, 2009, we received
net proceeds of approximately $280 million from the issuance of
24.2 million common shares in an underwritten public offering, net proceeds
of $148 million from the issuance of 14.3 million common shares
through a continuous offering program, proceeds of approximately
$57 million from the sale of approximately 4.9 million common shares
to our defined contribution plan and proceeds of approximately $15 million
from the sale of approximately 1.3 million common shares to participants in
our enhanced dividend reinvestment plan.
Credit and Receivables
Facilities. In October 2009, CenterPoint Houston terminated
its $600 million 364-day secured credit facility which had been arranged in
November 2008 following Hurricane Ike.
In
October 2009, the size of CERC Corp.’s revolving credit facility was reduced
from $950 million to $915 million through removal of Lehman Brothers
Bank, FSB (Lehman) as a lender. Prior to its removal, Lehman had a
$35 million commitment to lend. All credit facility loans to
CERC Corp. that were funded by Lehman were repaid in September
2009.
In
October 2009, CERC amended its receivables facility to extend the termination
date to October 8, 2010. Availability under CERC’s 364-day
receivables facility ranges from $150 million to $375 million,
reflecting seasonal changes in receivables balances.
As of
February 15, 2010, we had the following facilities (in millions):
|
Date
Executed
|
Company
|
Type
of
Facility
|
Size
of
Facility
|
Amount
Utilized
at
February
15,
2010 (1)
|
Termination
Date
|
||||||||
|
June
29, 2007
|
CenterPoint
Energy
|
Revolver
|
$ | 1,156 | $ | 20 | (2) |
June
29, 2012
|
|||||
|
June
29, 2007
|
CenterPoint
Houston
|
Revolver
|
289 | 4 | (2) |
June
29, 2012
|
|||||||
|
June
29, 2007
|
CERC
Corp.
|
Revolver
|
915 | - |
June
29, 2012
|
||||||||
|
October
9, 2009
|
CERC
|
Receivables
|
375 | - |
October
8, 2010
|
||||||||
________
|
|
(1)
|
Based
on the debt to earnings before interest, taxes, depreciation and
amortization (EBITDA) covenant contained in our $1.2 billion credit
facility, we would have been permitted to incur incremental borrowings on
a consolidated basis at December 31, 2009 of approximately $1.3
billion. Had the February 2010 amendment to such covenant described
below been in effect, we would have been permitted to incur an additional
$800 million of borrowings at such time in the event a qualifying disaster
occurred. Since amounts advanced under CERC Corp.'s receivables
facility are not included in this debt to EBITDA covenant calculation,
such amounts are not included in the estimated amounts of permitted
incremental borrowings.
|
|
|
(2)
|
Represents
outstanding letters of
credit.
|
Our
$1.2 billion credit facility has a first drawn cost of London Interbank
Offered Rate (LIBOR) plus 55 basis points based on our current credit ratings.
The facility contains a debt (excluding transition and system restoration bonds)
to EBITDA covenant (as those terms are defined in the
facility). Such covenant was modified twice in 2008 to provide
additional debt capacity. The second modification was to provide debt
capacity pending the financing of system restoration costs following Hurricane
Ike. That modification was terminated with CenterPoint Houston’s
issuance of bonds to securitize such costs in November 2009. In
February 2010, we amended our credit facility to modify the financial ratio
covenant to allow for a temporary increase of the permitted ratio of debt
(excluding transition and system restoration bonds) to EBITDA from 5 times to
5.5 times if CenterPoint Houston experiences damage from a natural disaster in
its service territory and we certify to the administrative agent that
CenterPoint Houston has incurred system restoration costs reasonably likely to
exceed $100 million in a calendar year, all or part of which CenterPoint Houston
intends to seek to recover through securitization financing. Such temporary
increase in the financial ratio covenant would be in effect from the date we
deliver our certification until the earliest to occur of (i) the completion of
the securitization financing, (ii) the first anniversary of our certification or
(iii) the revocation of such certification.
CenterPoint
Houston’s $289 million credit facility contains a debt (excluding
transition and system restoration bonds) to total capitalization covenant. The
facility’s first drawn cost is LIBOR plus 45 basis points based on CenterPoint
Houston’s current credit ratings.
CERC
Corp.’s $915 million credit facility’s first drawn cost is LIBOR plus 45
basis points based on CERC Corp.’s current credit ratings. The facility contains
a debt to total capitalization covenant.
Under our
$1.2 billion credit facility, CenterPoint Houston’s $289 million
credit facility and CERC Corp’s $915 million credit facility, an additional
utilization fee of 5 basis points applies to borrowings any time more than 50%
of the facility is utilized. The spread to LIBOR and the utilization fee
fluctuate based on the borrower’s credit rating.
Borrowings
under each of the facilities are subject to customary terms and conditions.
However, there is no requirement that we, CenterPoint Houston or CERC Corp. make
representations prior to borrowings as to the absence of material adverse
changes or litigation that could be expected to have a material adverse effect.
Borrowings under each of the credit facilities are subject to acceleration upon
the occurrence of events of default that we, CenterPoint Houston or CERC Corp.
consider customary.
We,
CenterPoint Houston and CERC Corp. are currently in compliance with the various
business and financial covenants contained in the respective credit facilities
as disclosed above.
55
Our $1.2 billion credit facility backstops a $1.0 billion CenterPoint
Energy commercial paper program under which we began issuing commercial paper in
June 2005. The $915 million CERC Corp. credit facility backstops a
$915 million commercial paper program under which CERC Corp. began issuing
commercial paper in February 2008. The CenterPoint Energy commercial paper is
rated "Not Prime" by Moody’s Investors Service, Inc. (Moody’s), "A-3" by
Standard & Poor’s Rating Services (S&P), a division of The
McGraw-Hill Companies, and "F3" by Fitch, Inc. (Fitch). The CERC Corp.
commercial paper is rated "P-3" by Moody’s, "A-3" by S&P, and "F2"
by Fitch.
As a result of the credit ratings on the two commercial paper programs, we do
not expect to be able to rely on the sale of commercial paper to fund all of our
short-term borrowing requirements. We cannot assure you that these ratings, or
the credit ratings set forth below in "─ Impact on Liquidity of a Downgrade
in Credit Ratings," will remain in effect for any given period of time or that
one or more of these ratings will not be lowered or withdrawn entirely by a
rating agency. We note that these credit ratings are not recommendations to buy,
sell or hold our securities and may be revised or withdrawn at any time by the
rating agency. Each rating should be evaluated independently of any other
rating. Any future reduction or withdrawal of one or more of our credit ratings
could have a material adverse impact on our ability to obtain short- and
long-term financing, the cost of such financings and the execution of our
commercial strategies.
Securities Registered with the
SEC. In October 2008, CenterPoint Energy and CenterPoint Houston jointly
registered indeterminate principal amounts of CenterPoint Houston’s general
mortgage bonds and CenterPoint Energy’s senior debt securities and junior
subordinated debt securities and an indeterminate number of CenterPoint Energy’s
shares of common stock, shares of preferred stock, as well as stock purchase
contracts and equity units. In addition, CERC Corp. has a shelf
registration statement covering $500 million principal amount of senior
debt securities.
Temporary
Investments. As of February 15, 2010, CenterPoint Houston had
external temporary investments of $450 million.
Money Pool. We
have a money pool through which the holding company and participating
subsidiaries can borrow or invest on a short-term basis. Funding needs are
aggregated and external borrowing or investing is based on the net cash
position. The net funding requirements of the money pool are expected to be met
with borrowings under our revolving credit facility or the sale of our
commercial paper.
Impact on Liquidity of a Downgrade
in Credit Ratings. As of February 15, 2010, Moody’s, S&P,
and Fitch had assigned the following credit ratings to senior debt of
CenterPoint Energy and certain subsidiaries:
|
Moody’s
|
S&P
|
Fitch
|
||||||||||
|
Company/Instrument
|
Rating
|
Outlook(1)
|
Rating
|
Outlook(2)
|
Rating
|
Outlook(3)
|
||||||
|
CenterPoint
Energy Senior Unsecured Debt
|
Ba1
|
Stable
|
BBB-
|
Negative
|
BBB-
|
Stable
|
||||||
|
CenterPoint
Houston Senior Secured Debt
|
Baa1
|
Positive
|
BBB+
|
Negative
|
A-
|
Stable
|
||||||
|
CERC
Corp. Senior Unsecured Debt
|
Baa3
|
Stable
|
BBB
|
Negative
|
BBB
|
Stable
|
||||||
__________
|
|
(1)
|
A
Moody’s rating outlook is an opinion regarding the likely direction of a
rating over the medium term.
|
|
|
(2)
|
An
S&P rating outlook assesses the potential direction of a long-term
credit rating over the intermediate to longer
term.
|
|
|
(3)
|
A
"stable" outlook from Fitch encompasses a one- to two-year horizon as to
the likely ratings direction.
|
A decline
in credit ratings could increase borrowing costs under our $1.2 billion
credit facility, CenterPoint Houston’s $289 million credit facility and
CERC Corp.’s $915 million credit facility. If our credit ratings or those
of CenterPoint Houston or CERC had been downgraded one notch by each of the
three principal credit rating agencies from the ratings that existed at
December 31, 2009, the impact on the borrowing costs under our bank credit
facilities would have been immaterial. A decline in credit ratings would also
increase the interest rate on long-term debt to be issued in the capital markets
and could negatively impact our ability to complete capital market
transactions.
CERC Corp. and its subsidiaries purchase natural gas from its
largest supplier under supply agreements that contain an aggregate credit
threshold of $120 million based on CERC Corp.’s S&P senior unsecured
long-term debt rating of BBB. Under these agreements, CERC may need to provide
collateral if the aggregate threshold is exceeded. Upgrades and downgrades from
this BBB rating will increase and decrease the aggregate credit threshold
accordingly.
CenterPoint
Energy Services, Inc. (CES), a wholly owned subsidiary of CERC Corp. operating
in our Competitive Natural Gas Sales and Services business segment,
provides comprehensive natural gas sales and services primarily to commercial
and industrial customers and electric and gas utilities throughout the central
and eastern United States. In order to economically hedge its exposure to
natural gas prices, CES uses derivatives with provisions standard for the
industry, including those pertaining to credit thresholds. Typically, the credit
threshold negotiated with each counterparty defines the amount of unsecured
credit that such counterparty will extend to CES. To the extent that the credit
exposure that a counterparty has to CES at a particular time does not exceed
that credit threshold, CES is not obligated to provide collateral.
Mark-to-market exposure in excess of the credit threshold is routinely
collateralized by CES. As of December 31, 2009, the amount posted as
collateral aggregated approximately $114 million ($84 million of which
is associated with price stabilization activities of our Natural Gas
Distribution business segment). Should the credit ratings of CERC Corp. (as the
credit support provider for CES) fall below certain levels, CES would be
required to provide additional collateral up to the amount of its previously
unsecured credit limit. We estimate that as of December 31, 2009, unsecured
credit limits extended to CES by counterparties aggregate $241 million;
however, utilized credit capacity was $67 million.
Pipeline
tariffs and contracts typically provide that if the credit ratings of a shipper
or the shipper’s guarantor drop below a threshold level, which is generally
investment grade ratings from both Moody’s and S&P, cash or other collateral
may be demanded from the shipper in an amount equal to the sum of three months’
charges for pipeline services plus the unrecouped cost of any lateral built for
such shipper. If the credit ratings of CERC Corp. decline below the applicable
threshold levels, CERC Corp. might need to provide cash or other collateral of
as much as $188 million as of December 31, 2009. The amount
of collateral will depend on seasonal variations in transportation
levels.
In
September 1999, we issued 2.0% Zero-Premium Exchangeable Subordinated Notes due
2029 (ZENS) having an original principal amount of $1.0 billion of which
$840 million remain outstanding at December 31, 2009. Each ZENS note
was originally exchangeable at the holder’s option at any time for an amount of
cash equal to 95% of the market value of the reference shares of Time Warner
Inc. common stock (TW Common) attributable to such note. The number
and identity of the reference shares attributable to each ZENS note are adjusted
for certain corporate events. As of December 31, 2009, the reference shares
for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of Time
Warner Cable Inc. common stock (TWC Common) and 0.045455 share of AOL Inc.
common stock (AOL Common), which reflects adjustments resulting from the March
2009 distribution by Time Warner Inc. of shares of TWC Common, Time Warner
Inc.’s March 2009 reverse stock split and the December 2009 distribution by Time
Warner Inc. of shares of AOL Common. If our creditworthiness were to drop
such that ZENS note holders thought our liquidity was adversely affected or the
market for the ZENS notes were to become illiquid, some ZENS note holders might
decide to exchange their ZENS notes for cash. Funds for the payment of cash upon
exchange could be obtained from the sale of the shares of TW Common, TWC Common
and AOL Common that we own or from other sources. We own shares of TW Common,
TWC Common and AOL Common equal to approximately 100% of the reference shares
used to calculate our obligation to the holders of the ZENS notes. ZENS note
exchanges result in a cash outflow because tax deferrals related to the ZENS
notes and TW Common, TWC Common and AOL Common shares would typically cease when
ZENS notes are exchanged or otherwise retired and TW Common, TWC Common and AOL
Common shares are sold. The ultimate tax liability related to the ZENS notes
continues to increase by the amount of the tax benefit realized each year, and
there could be a significant cash outflow when the taxes are paid as a result of
the retirement of the ZENS notes. The American Recovery and Reinvestment
Act of 2009 allows us to defer until 2014 taxes due as a result of the
retirement of ZENS notes that would have otherwise been payable in 2009 or 2010
and pay such taxes over the period from 2014 through 2018. Accordingly, if on
December 31, 2009, all ZENS notes had been exchanged for cash, we could
have deferred taxes of approximately $379 million that would have otherwise
been payable in 2009.
Cross Defaults. Under our
revolving credit facility, a payment default on, or a non-payment default that
permits acceleration of, any indebtedness exceeding $50 million by us or
any of our significant subsidiaries will cause a
57
default.
In addition, four outstanding series of our senior notes, aggregating
$950 million in principal amount as of February 15, 2010, provide that a
payment default by us, CERC Corp. or CenterPoint Houston in respect of, or an
acceleration of, borrowed money and certain other specified types of
obligations, in the aggregate principal amount of $50 million, will cause a
default. A default by CenterPoint Energy would not trigger a default under our
subsidiaries’ debt instruments or bank credit facilities.
Possible Acquisitions, Divestitures
and Joint Ventures. From time to time, we consider the acquisition or the
disposition of assets or businesses or possible joint ventures or other joint
ownership arrangements with respect to assets or businesses. Any determination
to take any action in this regard will be based on market conditions and
opportunities existing at the time, and accordingly, the timing, size or success
of any efforts and the associated potential capital commitments are
unpredictable. We may seek to fund all or part of any such efforts with proceeds
from debt and/or equity issuances. Debt or equity financing may not, however, be
available to us at that time due to a variety of events, including, among
others, maintenance of our credit ratings, industry conditions, general economic
conditions, market conditions and market perceptions.
Other Factors that Could Affect Cash
Requirements. In addition to the above factors, our liquidity
and capital resources could be affected by:
|
|
•
|
cash
collateral requirements that could exist in connection with certain
contracts, including gas purchases, gas price and weather hedging and gas
storage activities of our Natural Gas Distribution and Competitive Natural
Gas Sales and Services business
segments;
|
|
|
•
|
acceleration
of payment dates on certain gas supply contracts under certain
circumstances, as a result of increased gas prices and concentration of
natural gas suppliers;
|
|
|
•
|
increased
costs related to the acquisition of natural
gas;
|
|
|
•
|
increases
in interest expense in connection with debt refinancings and borrowings
under credit facilities;
|
|
|
•
|
various
regulatory actions;
|
|
|
•
|
the
ability of RRI and its subsidiaries to satisfy their obligations in
respect of RRI’s indemnity obligations to us and our subsidiaries or in
connection with the contractual obligations to a third party pursuant to
which CERC is a guarantor;
|
|
|
•
|
the
ability of REPs that are subsidiaries of NRG Retail LLC and TXU Energy,
which are CenterPoint Houston’s two largest customers, to satisfy their
obligations to us and our
subsidiaries;
|
|
|
•
|
slower
customer payments and increased write-offs of receivables due to higher
gas prices or changing economic
conditions;
|
|
|
•
|
the
outcome of litigation brought by and against
us;
|
|
|
•
|
contributions
to pension and postretirement benefit
plans;
|
|
|
•
|
restoration
costs and revenue losses resulting from natural disasters such as
hurricanes and the timing of recovery of such restoration costs;
and
|
|
|
•
|
various
other risks identified in "Risk Factors" in Item 1A of this
report.
|
Certain Contractual Limits on Our
Ability to Issue Securities and Borrow Money. CenterPoint Houston’s
credit facilities limit CenterPoint Houston’s debt (excluding transition and
system restoration bonds) as a percentage of its total capitalization to 65%.
CERC Corp.’s bank facility and its receivables facility limit CERC’s debt as a
percentage of its total capitalization to 65%. Our $1.2 billion credit
facility contains a debt, excluding transition and system restoration bonds, to
EBITDA covenant. Such covenant was modified twice in 2008 to provide additional
debt capacity. The second modification was to provide debt capacity
pending the financing of system restoration
costs
following Hurricane Ike. That modification was terminated with
CenterPoint Houston’s issuance of bonds to securitize such costs in November
2009. In February 2010, we amended our $1.2 billion credit
facility to modify this covenant to allow for a temporary increase in debt
capacity if CenterPoint Houston experiences damage from a natural disaster in
its service territory that meets certain criteria. Additionally, CenterPoint
Houston has contractually agreed that it will not issue additional first
mortgage bonds, subject to certain exceptions.
CRITICAL
ACCOUNTING POLICIES
A
critical accounting policy is one that is both important to the presentation of
our financial condition and results of operations and requires management to
make difficult, subjective or complex accounting estimates. An accounting
estimate is an approximation made by management of a financial statement
element, item or account in the financial statements. Accounting estimates in
our historical consolidated financial statements measure the effects of past
business transactions or events, or the present status of an asset or liability.
The accounting estimates described below require us to make assumptions about
matters that are highly uncertain at the time the estimate is made.
Additionally, different estimates that we could have used or changes in an
accounting estimate that are reasonably likely to occur could have a material
impact on the presentation of our financial condition or results of operations.
The circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the effect of matters that are
inherently uncertain. Estimates and assumptions about future events and their
effects cannot be predicted with certainty. We base our estimates on historical
experience and on various other assumptions that we believe to be reasonable
under the circumstances, the results of which form the basis for making
judgments. These estimates may change as new events occur, as more experience is
acquired, as additional information is obtained and as our operating environment
changes. Our significant accounting policies are discussed in Note 2 to our
consolidated financial statements. We believe the following accounting policies
involve the application of critical accounting estimates. Accordingly, these
accounting estimates have been reviewed and discussed with the audit committee
of the board of directors.
Accounting
for Rate Regulation
Accounting
guidance for regulated operations provides that rate-regulated entities account
for and report assets and liabilities consistent with the recovery of those
incurred costs in rates if the rates established are designed to recover the
costs of providing the regulated service and if the competitive environment
makes it probable that such rates can be charged and collected. Our Electric
Transmission & Distribution business segment, our Natural Gas
Distribution business segment and portions of our Interstate Pipelines business
segment apply this accounting guidance. Certain expenses and revenues subject to
utility regulation or rate determination normally reflected in income are
deferred on the balance sheet as regulatory assets or liabilities and are
recognized in income as the related amounts are included in service rates and
recovered from or refunded to customers. Regulatory assets and
liabilities are recorded when it is probable that these items will be recovered
or reflected in future rates. Determining probability requires
significant judgment on the part of management and includes, but is not limited
to, consideration of testimony presented in regulatory hearings, proposed
regulatory decisions, final regulatory orders and the strength or status of
applications for rehearing or state court appeals. If events were to
occur that would make the recovery of these assets and liabilities no longer
probable, we would be required to write off or write down these regulatory
assets and liabilities. At December 31, 2009, we had recorded
regulatory assets of $3.7 billion and regulatory liabilities of
$921 million.
Impairment
of Long-Lived Assets and Intangibles
We review
the carrying value of our long-lived assets, including goodwill and identifiable
intangibles, whenever events or changes in circumstances indicate that such
carrying values may not be recoverable, and at least annually for goodwill as
required by accounting guidance for goodwill and other intangible assets. No
impairment of goodwill was indicated based on our annual analysis at
July 1, 2009. Unforeseen events and changes in circumstances and market
conditions and material differences in the value of long-lived assets and
intangibles due to changes in estimates of future cash flows, interest rates,
regulatory matters and operating costs could negatively affect the fair value of
our assets and result in an impairment charge.
Fair
value is the amount at which the asset could be bought or sold in a current
transaction between willing parties and may be estimated using a number of
techniques, including quoted market prices or valuations by third
parties,
present value
techniques based on estimates of cash flows, or multiples of earnings or revenue
performance measures. The fair value of the asset could be different using
different estimates and assumptions in these valuation techniques.
Unbilled
Energy Revenues
Revenues
related to electricity delivery and natural gas sales and services are generally
recognized upon delivery to customers. However, the determination of deliveries
to individual customers is based on the reading of their meters, which is
performed on a systematic basis throughout the month. At the end of each month,
deliveries to customers since the date of the last meter reading are estimated
and the corresponding unbilled revenue is estimated. Unbilled electricity
delivery revenue is estimated each month based on daily supply volumes,
applicable rates and analyses reflecting significant historical trends and
experience. Unbilled natural gas sales are estimated based on estimated
purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates
in effect. As additional information becomes available, or actual amounts are
determinable, the recorded estimates are revised. Consequently, operating
results can be affected by revisions to prior accounting estimates.
Pension
and Other Retirement Plans
We
sponsor pension and other retirement plans in various forms covering all
employees who meet eligibility requirements. We use several statistical and
other factors that attempt to anticipate future events in calculating the
expense and liability related to our plans. These factors include assumptions
about the discount rate, expected return on plan assets and rate of future
compensation increases as estimated by management, within certain guidelines. In
addition, our actuarial consultants use subjective factors such as withdrawal
and mortality rates. The actuarial assumptions used may differ materially from
actual results due to changing market and economic conditions, higher or lower
withdrawal rates or longer or shorter life spans of participants. These
differences may result in a significant impact to the amount of pension expense
recorded. Please read "- Other Significant Matters - Pension Plans"
for further discussion.
NEW
ACCOUNTING PRONOUNCEMENTS
See
Note 2(o) to our consolidated financial statements for a discussion of new
accounting pronouncements that affect us.
OTHER
SIGNIFICANT MATTERS
Pension Plans. As
discussed in Note 2(p) to our consolidated financial statements, we
maintain a non-contributory qualified defined benefit pension plan covering
substantially all employees. Employer contributions for the qualified plan are
based on actuarial computations that establish the minimum contribution required
under the Employee Retirement Income Security Act of 1974 (ERISA) and the
maximum deductible contribution for income tax purposes.
Under the
terms of our pension plan, we reserve the right to change, modify or terminate
the plan. Our funding policy is to review amounts annually and contribute an
amount at least equal to the minimum contribution required under
ERISA.
We made
no contribution to the qualified pension plan in 2008; however, a discretionary
contribution of $13 million was made in 2009. The minimum funding
requirements for this plan did not require contributions for the respective
years.
Additionally,
we maintain an unfunded non-qualified benefit restoration plan that allows
participants to receive the benefits to which they would have been entitled
under our non-contributory pension plan except for the federally mandated limits
on qualified plan benefits or on the level of compensation on which qualified
plan benefits may be calculated. Employer contributions for the non-qualified
benefit restoration plan represent benefit payments made to participants and
totaled $8 million and $7 million in 2008 and 2009,
respectively.
Changes
in pension obligations and assets may not be immediately recognized as pension
expense in the income statement, but generally are recognized in future years
over the remaining average service period of plan participants. As such,
significant portions of pension expense recorded in any period may not reflect
the actual level of benefit payments provided to plan participants.
As the
sponsor of a plan, we are required to (a) recognize on our balance sheet as
an asset a plan’s over-funded status or as a liability such plan’s under-funded
status, (b) measure a plan’s assets and obligations as of the end of our
fiscal year and (c) recognize changes in the funded status of our plans in
the year that changes occur through adjustments to other comprehensive
income.
At
December 31, 2009, the projected benefit obligation exceeded the market
value of plan assets of our pension plans by $434 million. Changes in
interest rates or the market values of the securities held by the plan during
2010 could materially, positively or negatively, change our funded status and
affect the level of pension expense and required contributions.
Pension
cost was $15 million, $1 million and $111 million for 2007, 2008
and 2009, respectively, of which $12 million, $1 million and
$60 million impacted pre-tax earnings. CenterPoint Houston’s actuarially
determined pension and other postemployment expenses for 2009 in excess of the
2007 base year amount are being deferred for rate making purposes until its next
general rate case pursuant to Texas law. CenterPoint Houston deferred
as a regulatory asset $32 million in pension and other postemployment
expenses during the year ended December 31, 2009.
The
calculation of pension expense and related liabilities requires the use of
assumptions. Changes in these assumptions can result in different expense and
liability amounts, and future actual experience can differ from the assumptions.
Two of the most critical assumptions are the expected long-term rate of return
on plan assets and the assumed discount rate.
As of
December 31, 2009, our qualified pension plan had an expected long-term
rate of return on plan assets of 8.00%, which was unchanged from the rate
assumed as of December 31, 2008. We believe that our actual asset
allocation, on average, will approximate the targeted allocation and the
estimated return on net assets. We regularly review our actual asset allocation
and periodically rebalance plan assets as appropriate.
As of
December 31, 2009, the projected benefit obligation was calculated assuming
a discount rate of 5.70%, which is a 1.20% decrease from the 6.90% discount rate
assumed in 2008. The discount rate was determined by reviewing yields on
high-quality bonds that receive one of the two highest ratings given by a
recognized rating agency and the expected duration of pension obligations
specific to the characteristics of our plan.
Pension
cost for 2010, including the benefit restoration plan, is estimated to be
$86 million, of which we expect $44 million to impact pre-tax
earnings, based on an expected return on plan assets of 8.0% and a discount rate
of 5.70% as of December 31, 2009. If the expected return assumption were
lowered by 0.5% (from 8.00% to 7.50%), 2010 pension cost would increase by
approximately $7 million.
As of
December 31, 2009, the pension plan projected benefit obligation, including
the unfunded benefit restoration plan, exceeded plan assets by
$434 million. If the discount rate were lowered by 0.5% (from
5.70% to 5.20%), the assumption change would increase our projected benefit
obligation and 2010 pension expense by approximately $83 million and
$4 million, respectively. In addition, the assumption change would impact
our Consolidated Balance Sheet by increasing the regulatory asset recorded as of
December 31, 2009 by $66 million and would result in a charge to
comprehensive income in 2009 of $11 million, net of tax.
Future
changes in plan asset returns, assumed discount rates and various other factors
related to the pension plan will impact our future pension expense and
liabilities. We cannot predict with certainty what these factors will
be.
Item 7A. Quantitative and
Qualitative Disclosures About Market Risk
Impact
of Changes in Interest Rates and Energy Commodity Prices
We are
exposed to various market risks. These risks arise from transactions entered
into in the normal course of business and are inherent in our consolidated
financial statements. Most of the revenues and income from our business
activities are impacted by market risks. Categories of market risk include
exposure to commodity prices through non-trading activities, interest rates and
equity prices. A description of each market risk is set forth
below:
|
|
•
|
Commodity
price risk results from exposures to changes in spot prices, forward
prices and price volatilities of commodities, such as natural gas, natural
gas liquids and other energy
commodities.
|
|
|
•
|
Interest
rate risk primarily results from exposures to changes in the level of
borrowings and changes in interest
rates.
|
|
|
•
|
Equity
price risk results from exposures to changes in prices of individual
equity securities.
|
Management
has established comprehensive risk management policies to monitor and manage
these market risks. We manage these risk exposures through the implementation of
our risk management policies and framework. We manage our commodity price risk
exposures through the use of derivative financial instruments and derivative
commodity instrument contracts. During the normal course of business, we review
our hedging strategies and determine the hedging approach we deem appropriate
based upon the circumstances of each situation.
Derivative
instruments such as futures, forward contracts, swaps and options derive their
value from underlying assets, indices, reference rates or a combination of these
factors. These derivative instruments include negotiated contracts, which are
referred to as over-the-counter derivatives, and instruments that are listed and
traded on an exchange.
Derivative
transactions are entered into in our non-trading operations to manage and hedge
certain exposures, such as exposure to changes in natural gas prices. We believe
that the associated market risk of these instruments can best be understood
relative to the underlying assets or risk being hedged.
As of
December 31, 2009, we had outstanding long-term debt, bank loans, lease
obligations and obligations under our ZENS that subject us to the risk of loss
associated with movements in market interest rates.
Our
floating-rate obligations aggregated $1.5 billion and $-0- at
December 31, 2008 and 2009, respectively.
At
December 31, 2008 and 2009, we had outstanding fixed-rate debt (excluding
indexed debt securities) aggregating $9.0 billion and $9.9 billion,
respectively, in principal amount and having a fair value of $8.5 billion
and $10.4 billion, respectively. Because these instruments are fixed-rate,
they do not expose us to the risk of loss in earnings due to changes in market
interest rates (please read Note 8 to our consolidated financial
statements). However, the fair value of these instruments would increase by
approximately $260 million if interest rates were to decline by 10% from
their levels at December 31, 2009. In general, such an increase in fair
value would impact earnings and cash flows only if we were to reacquire all or a
portion of these instruments in the open market prior to their
maturity.
As
discussed in Note 6 to our consolidated financial statements, the ZENS
obligation is bifurcated into a debt component and a derivative component. The
debt component of $121 million at December 31, 2009 was a fixed-rate
obligation and, therefore, did not expose us to the risk of loss in earnings due
to changes in market interest rates. However, the fair value of the debt
component would increase by approximately $20 million if interest rates
were to decline by 10% from levels at December 31, 2009. Changes in the
fair value of the derivative component, a $201 million recorded liability
at December 31, 2009, are recorded in our Statements of Consolidated Income
and, therefore, we are exposed to changes in the fair value of the derivative
component as a result of changes in the underlying risk-free interest rate. If
the risk-free interest rate were to increase by 10% from December 31, 2009
levels, the fair value of the derivative component liability would increase by
approximately $5 million, which would be recorded as an unrealized loss in
our Statements of Consolidated Income.
62
Equity
Market Value Risk
We are
exposed to equity market value risk through our ownership of 7.2 million
shares of TW Common, 1.8 million shares of TWC Common and 0.7 million
shares of AOL Common, which we hold to facilitate our ability to meet our
obligations under the ZENS. Please read Note 6 to our consolidated
financial statements for a discussion of our ZENS obligation. A decrease of 10%
from the December 31, 2009 aggregate market value of these shares would
result in a net loss of approximately $5 million, which would be recorded
as an unrealized loss in our Statements of Consolidated Income.
Commodity
Price Risk From Non-Trading Activities
We use
derivative instruments as economic hedges to offset the commodity price exposure
inherent in our businesses. The stand-alone commodity risk created by these
instruments, without regard to the offsetting effect of the underlying exposure
these instruments are intended to hedge, is described below. We measure the
commodity risk of our non-trading energy derivatives using a sensitivity
analysis. The sensitivity analysis performed on our non-trading energy
derivatives measures the potential loss in fair value based on a hypothetical
10% movement in energy prices. At December 31, 2009, the recorded fair
value of our non-trading energy derivatives was a net liability of
$134 million (before collateral). The net liability consisted of a net
liability of $143 million associated with price stabilization activities of
our Natural Gas Distribution business segment and a net asset of $9 million
related to our Competitive Natural Gas Sales and Services business segment. Net
assets or liabilities related to the price stabilization activities correspond
directly with net over/under recovered gas cost liabilities or assets on the
balance sheet. A decrease of 10% in the market prices of energy commodities from
their December 31, 2009 levels would have increased the fair value of our
non-trading energy derivatives net liability by
$31 million. However, the consolidated income statement impact
of this same 10% decrease in market prices would be an increase in income of
$3 million.
The above
analysis of the non-trading energy derivatives utilized for commodity price risk
management purposes does not include the favorable impact that the same
hypothetical price movement would have on our physical purchases and sales of
natural gas to which the hedges relate. Furthermore, the non-trading energy
derivative portfolio is managed to complement the physical transaction
portfolio, reducing overall risks within limits. Therefore, the adverse impact
to the fair value of the portfolio of non-trading energy derivatives held for
hedging purposes associated with the hypothetical changes in commodity prices
referenced above is expected to be substantially offset by a favorable impact on
the underlying hedged physical transactions.
Item 8. Financial Statements and
Supplementary Data
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Shareholders of
CenterPoint
Energy, Inc.
Houston,
Texas
We have
audited the accompanying consolidated balance sheets of CenterPoint Energy, Inc.
and subsidiaries (the "Company") as of December 31, 2009 and 2008, and the
related statements of consolidated income, comprehensive income, shareholders’
equity, and cash flows for each of the three years in the period ended December
31, 2009. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our
opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of CenterPoint Energy, Inc. and subsidiaries at
December 31, 2009 and 2008, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2009, in
conformity with accounting principles generally accepted in the United States of
America.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company's internal control over financial
reporting as of December 31, 2009, based on the criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 26, 2010 expressed an
unqualified opinion on the Company's internal control over financial
reporting.
/s/
DELOITTE & TOUCHE LLP
Houston,
Texas
February 26,
2010
To
the Board of Directors and Shareholders of
CenterPoint
Energy, Inc.
Houston,
Texas
We
have audited the internal control over financial reporting of CenterPoint
Energy, Inc. and subsidiaries (the "Company") as of December 31, 2009, based on
criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Company's management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting,
included in the accompanying Management’s Annual Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on the
Company's internal control over financial reporting based on our
audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness
of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A
company's internal control over financial reporting is a process designed by, or
under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control
over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial
statements.
Because
of the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In
our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2009, based on the
criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We
have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements as of and for the year ended December 31, 2009 of the Company and our
report dated February 26, 2010 expressed an unqualified
opinion on those financial statements.
/s/
DELOITTE & TOUCHE LLP
Houston,
Texas
February
26, 2010
MANAGEMENT’S
ANNUAL REPORT ON INTERNAL CONTROL
OVER
FINANCIAL REPORTING
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting. Internal control over financial reporting is
defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities
Exchange Act of 1934 as a process designed by, or under the supervision of, the
company’s principal executive and principal financial officers and effected by
the company’s board of directors, management and other personnel, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles and includes those policies and
procedures that:
|
|
•
|
Pertain
to the maintenance of records that in reasonable detail accurately and
fairly reflect the transactions and dispositions of the assets of the
company;
|
|
|
•
|
Provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and
directors of the company; and
|
|
|
•
|
Provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of the company’s assets that
could have a material effect on the financial
statements.
|
Management
has designed its internal control over financial reporting to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements in accordance with accounting principles generally
accepted in the United States of America. Management’s assessment included
review and testing of both the design effectiveness and operating effectiveness
of controls over all relevant assertions related to all significant accounts and
disclosures in the financial statements.
All
internal control systems, no matter how well designed, have inherent
limitations. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement
preparation and presentation. Projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Under the
supervision and with the participation of our management, including our
principal executive officer and principal financial officer, we conducted an
evaluation of the effectiveness of our internal control over financial reporting
based on the framework in Internal Control - Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission. Based on
our evaluation under the framework in Internal Control - Integrated
Framework, our management has concluded that our internal control over financial
reporting was effective as of December 31, 2009.
Deloitte &
Touche LLP, the Company’s independent registered public accounting firm, has
issued an attestation report on the effectiveness of our internal control over
financial reporting as of December 31, 2009 which is included herein on
page 65.
|
/s/ DAVID M.
MCCLANAHAN
|
|
|
President
and Chief Executive Officer
|
|
|
/s/ GARY L.
WHITLOCK
|
|
|
Executive
Vice President and Chief
|
|
|
Financial
Officer
|
February
26, 2010
CENTERPOINT
ENERGY, INC. AND SUBSIDIARIES
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
(In
millions,
|
||||||||||||
|
except
for share amounts)
|
||||||||||||
|
Revenues
|
$ | 9,623 | $ | 11,322 | $ | 8,281 | ||||||
|
Expenses:
|
||||||||||||
|
Natural
gas
|
5,995 | 7,466 | 4,371 | |||||||||
|
Operation
and maintenance
|
1,440 | 1,502 | 1,664 | |||||||||
|
Depreciation
and amortization
|
631 | 708 | 743 | |||||||||
|
Taxes
other than income taxes
|
372 | 373 | 379 | |||||||||
|
Total
|
8,438 | 10,049 | 7,157 | |||||||||
|
Operating
Income
|
1,185 | 1,273 | 1,124 | |||||||||
|
Other
Income (Expense):
|
||||||||||||
|
Gain
(loss) on marketable securities
|
(114 | ) | (139 | ) | 82 | |||||||
|
Gain
(loss) on indexed debt securities
|
111 | 128 | (68 | ) | ||||||||
|
Interest
and other finance charges
|
(509 | ) | (468 | ) | (513 | ) | ||||||
|
Interest
on transition and system restoration bonds
|
(123 | ) | (136 | ) | (131 | ) | ||||||
|
Distribution
from AOL Time Warner litigation settlement
|
32 | - | 3 | |||||||||
|
Additional
distribution to ZENS holders
|
(27 | ) | - | (3 | ) | |||||||
|
Equity
in earnings of unconsolidated affiliates
|
16 | 51 | 15 | |||||||||
|
Other,
net
|
17 | 14 | 39 | |||||||||
|
Total
|
(597 | ) | (550 | ) | (576 | ) | ||||||
|
Income
Before Income Taxes
|
588 | 723 | 548 | |||||||||
|
Income
tax expense
|
(193 | ) | (277 | ) | (176 | ) | ||||||
|
Net
Income
|
$ | 395 | $ | 446 | $ | 372 | ||||||
|
Basic
Earnings Per Share
|
$ | 1.23 | $ | 1.32 | $ | 1.02 | ||||||
|
Diluted
Earnings Per Share
|
$ | 1.15 | $ | 1.30 | $ | 1.01 | ||||||
See Notes
to CenterPoint Energy’s Consolidated Financial Statements
CENTERPOINT
ENERGY, INC. AND SUBSIDIARIES
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Net
income
|
$ | 395 | $ | 446 | $ | 372 | ||||||
|
Other
comprehensive income (loss):
|
||||||||||||
|
Adjustment
to pension and other postretirement plans (net of tax of $28, $32 and
$2)
|
34 | (79 | ) | 7 | ||||||||
|
Net
deferred gain (loss) from cash flow hedges (net of tax of $6, $2 and
$-0-)
|
11 | (4 | ) | - | ||||||||
|
Reclassification
of deferred gain from cash flow hedges realized in net income
(net
of tax of $14, $2 and $-0-)
|
(20 | ) | (4 | ) | - | |||||||
|
Other
comprehensive income (loss)
|
25 | (87 | ) | 7 | ||||||||
|
Comprehensive
income
|
$ | 420 | $ | 359 | $ | 379 | ||||||
See Notes
to CenterPoint Energy’s Consolidated Financial Statements
CENTERPOINT
ENERGY, INC. AND SUBSIDIARIES
|
December 31,
2008
|
December 31,
2009
|
|||||||
|
(In
millions)
|
||||||||
|
ASSETS
|
||||||||
|
Current
Assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 167 | $ | 740 | ||||
|
Investment
in marketable securities
|
218 | 300 | ||||||
|
Accounts
receivable, net
|
1,009 | 790 | ||||||
|
Accrued
unbilled revenues
|
541 | 485 | ||||||
|
Inventory
|
569 | 327 | ||||||
|
Non-trading
derivative assets
|
118 | 39 | ||||||
|
Prepaid
expense and other current assets
|
413 | 223 | ||||||
|
Total
current assets
|
3,035 | 2,904 | ||||||
|
Property,
Plant and Equipment, net
|
10,296 | 10,788 | ||||||
|
Other
Assets:
|
||||||||
|
Goodwill
|
1,696 | 1,696 | ||||||
|
Regulatory
assets
|
3,684 | 3,677 | ||||||
|
Non-trading
derivative assets
|
20 | 15 | ||||||
|
Investment
in unconsolidated affiliates
|
345 | 463 | ||||||
|
Notes
receivable from unconsolidated affiliates
|
323 | - | ||||||
|
Other
|
277 | 230 | ||||||
|
Total
other assets
|
6,345 | 6,081 | ||||||
|
Total
Assets
|
$ | 19,676 | $ | 19,773 | ||||
|
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
||||||||
|
Current
Liabilities:
|
||||||||
|
Short-term
borrowings
|
$ | 153 | $ | 55 | ||||
|
Current
portion of transition and system restoration bonds long-term
debt
|
208 | 241 | ||||||
|
Current
portion of indexed debt
|
117 | 121 | ||||||
|
Current
portion of other long-term debt
|
8 | 541 | ||||||
|
Indexed
debt securities derivative
|
133 | 201 | ||||||
|
Accounts
payable
|
897 | 648 | ||||||
|
Taxes
accrued
|
189 | 148 | ||||||
|
Interest
accrued
|
180 | 181 | ||||||
|
Non-trading
derivative liabilities
|
87 | 51 | ||||||
|
Accumulated
deferred income taxes, net
|
372 | 406 | ||||||
|
Other
|
504 | 445 | ||||||
|
Total
current liabilities
|
2,848 | 3,038 | ||||||
|
Other
Liabilities:
|
||||||||
|
Accumulated
deferred income taxes, net
|
2,608 | 2,776 | ||||||
|
Unamortized
investment tax credits
|
24 | 16 | ||||||
|
Non-trading
derivative liabilities
|
47 | 42 | ||||||
|
Benefit
obligations
|
849 | 861 | ||||||
|
Regulatory
liabilities
|
821 | 921 | ||||||
|
Other
|
276 | 361 | ||||||
|
Total
other liabilities
|
4,625 | 4,977 | ||||||
|
Long-term
Debt:
|
||||||||
|
Transition
and system restoration bonds
|
2,381 | 2,805 | ||||||
|
Other
|
7,800 | 6,314 | ||||||
|
Total
long-term debt
|
10,181 | 9,119 | ||||||
|
Commitments
and Contingencies (Note 10)
|
||||||||
|
Shareholders’
Equity
|
2,022 | 2,639 | ||||||
|
Total
Liabilities and Shareholders’ Equity
|
$ | 19,676 | $ | 19,773 | ||||
See Notes
to CenterPoint Energy’s Consolidated Financial Statements
CENTERPOINT
ENERGY, INC. AND SUBSIDIARIES
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Cash
Flows from Operating Activities:
|
||||||||||||
|
Net
income
|
$ | 395 | $ | 446 | $ | 372 | ||||||
|
Adjustments
to reconcile income from continuing operations to net cash provided by
operating activities:
|
||||||||||||
|
Depreciation
and amortization
|
631 | 708 | 743 | |||||||||
|
Amortization
of deferred financing costs
|
69 | 29 | 37 | |||||||||
|
Deferred
income taxes
|
- | 487 | 269 | |||||||||
|
Unrealized
loss (gain) on marketable securities
|
114 | 139 | (82 | ) | ||||||||
|
Unrealized
loss (gain) on indexed debt securities
|
(111 | ) | (128 | ) | 68 | |||||||
|
Write-down
of natural gas inventory
|
11 | 30 | 6 | |||||||||
|
Equity
in earnings of unconsolidated affiliates, net of distributions
|
(13 | ) | (51 | ) | (3 | ) | ||||||
|
Changes
in other assets and liabilities:
|
||||||||||||
|
Accounts
receivable and unbilled revenues, net
|
- | (82 | ) | 283 | ||||||||
|
Inventory
|
(102 | ) | (109 | ) | 236 | |||||||
|
Accounts
payable
|
(185 | ) | 87 | (237 | ) | |||||||
|
Fuel
cost over (under) recovery
|
(93 | ) | 45 | (5 | ) | |||||||
|
Non-trading
derivatives, net
|
11 | (25 | ) | 28 | ||||||||
|
Margin
deposits, net
|
65 | (182 | ) | 116 | ||||||||
|
Interest
and taxes accrued
|
(33 | ) | (118 | ) | (41 | ) | ||||||
|
Net
regulatory assets and liabilities
|
81 | (366 | ) | - | ||||||||
|
Other
current assets
|
13 | (27 | ) | 27 | ||||||||
|
Other
current liabilities
|
(20 | ) | 29 | 6 | ||||||||
|
Other
assets
|
(20 | ) | (20 | ) | (1 | ) | ||||||
|
Other
liabilities
|
(51 | ) | (8 | ) | 3 | |||||||
|
Other,
net
|
12 | (33 | ) | 16 | ||||||||
|
Net
cash provided by operating activities
|
774 | 851 | 1,841 | |||||||||
|
Cash
Flows from Investing Activities:
|
||||||||||||
|
Capital
expenditures
|
(1,114 | ) | (1,020 | ) | (1,160 | ) | ||||||
|
Decrease
(increase) in restricted cash of transition and system restoration bond
companies
|
(1 | ) | (11 | ) | 26 | |||||||
|
Decrease
(increase) in notes receivable from unconsolidated affiliates
|
(148 | ) | (175 | ) | 323 | |||||||
|
Investment
in unconsolidated affiliates
|
(39 | ) | (206 | ) | (115 | ) | ||||||
|
Other,
net
|
2 | 44 | 30 | |||||||||
|
Net
cash used in investing activities
|
(1,300 | ) | (1,368 | ) | (896 | ) | ||||||
|
Cash
Flows from Financing Activities:
|
||||||||||||
|
Increase
(decrease) in short-term borrowings, net
|
45 | (79 | ) | (98 | ) | |||||||
|
Revolving
credit facilities, net
|
331 | 1,110 | (1,441 | ) | ||||||||
|
Proceeds
from long-term debt
|
900 | 1,088 | 1,165 | |||||||||
|
Payments
of long-term debt
|
(548 | ) | (1,373 | ) | (222 | ) | ||||||
|
Debt
issuance costs
|
(9 | ) | (26 | ) | (10 | ) | ||||||
|
Payment
of common stock dividends
|
(218 | ) | (246 | ) | (276 | ) | ||||||
|
Proceeds
from issuance of common stock, net
|
22 | 80 | 504 | |||||||||
|
Other,
net
|
5 | 1 | 6 | |||||||||
|
Net
cash provided by (used in) financing activities
|
528 | 555 | (372 | ) | ||||||||
|
Net
Increase in Cash and Cash Equivalents
|
2 | 38 | 573 | |||||||||
|
Cash
and Cash Equivalents at Beginning of Year
|
127 | 129 | 167 | |||||||||
|
Cash
and Cash Equivalents at End of Year
|
$ | 129 | $ | 167 | $ | 740 | ||||||
|
Supplemental
Disclosure of Cash Flow Information:
|
||||||||||||
|
Cash
Payments:
|
||||||||||||
|
Interest,
net of capitalized interest
|
$ | 572 | $ | 586 | $ | 624 | ||||||
|
Income
taxes (refunds), net
|
205 | (84 | ) | (9 | ) | |||||||
|
Non-cash
transactions:
|
||||||||||||
|
Accounts
payable related to capital expenditures
|
75 | 96 | 84 | |||||||||
See Notes
to CenterPoint Energy’s Consolidated Financial Statements
CENTERPOINT
ENERGY, INC. AND SUBSIDIARIES
|
2007
|
2008
|
2009 | |||||||||||||
|
Shares
|
Amount
|
Shares
|
Amount |
Shares
|
Amount
|
||||||||||
|
(In
millions of dollars and shares)
|
|||||||||||||||
|
Preference
Stock, none outstanding
|
- | $ | - | - | $ | - | - | $ | - | ||||||
|
Cumulative
Preferred Stock, $0.01 par value; authorized 20,000,000 shares,
none outstanding
|
- | - | - | - | - | - | |||||||||
|
Common
Stock, $0.01 par value; authorized
1,000,000,000 shares
|
|||||||||||||||
|
Balance,
beginning of year
|
314 | 3 | 323 | 3 | 346 | 3 | |||||||||
|
Issuances
related to benefit and investment plans
|
2 | - | 6 | - | 7 | - | |||||||||
|
Issuances
related to convertible debt conversions
|
7 | - | 17 | - | - | - | |||||||||
|
Issuances
related to public offerings
|
- | - | - | - | 38 | 1 | |||||||||
|
Balance,
end of year
|
323 | 3 | 346 | 3 | 391 | 4 | |||||||||
|
Additional
Paid-in-Capital
|
|||||||||||||||
|
Balance,
beginning of year
|
2,977 | 3,046 | 3,158 | ||||||||||||
|
Cumulative
effect of adoption of convertible debt pronouncement (See Note
2(o))
|
23 | - | - | ||||||||||||
|
Balance,
beginning of year (as adjusted)
|
3,000 | 3,046 | 3,158 | ||||||||||||
|
Issuances
related to benefit and investment plans
|
46 | 112 | 86 | ||||||||||||
|
Issuances
related to public offerings, net of issuance costs
|
- | - | 427 | ||||||||||||
|
Balance,
end of year
|
3,046 | 3,158 | 3,671 | ||||||||||||
|
Accumulated
Deficit
|
|||||||||||||||
|
Balance,
beginning of year
|
(1,355 | ) | (1,194 | ) | (1,008 | ) | |||||||||
|
Cumulative
effect of adoption of convertible debt pronouncement (See Note
2(o))
|
(18 | ) | - | - | |||||||||||
|
Cumulative
effect of change in accounting principle (see Note 2(p))
|
- | (15 | ) | - | |||||||||||
|
Balance,
beginning of year (as adjusted)
|
(1,373 | ) | (1,209 | ) | (1,008 | ) | |||||||||
|
Net
income
|
395 | 446 | 372 | ||||||||||||
|
Cumulative
effect of uncertain tax positions standard
|
2 | - | - | ||||||||||||
|
Common
stock dividends - $0.68 per share in 2007, $0.73 per share
in 2008, and $0.76 per share in 2009
|
(218 | ) | (245 | ) | (276 | ) | |||||||||
|
Balance,
end of year
|
(1,194 | ) | (1,008 | ) | (912 | ) | |||||||||
|
Accumulated
Other Comprehensive Loss
|
|||||||||||||||
|
Balance,
end of year:
|
|||||||||||||||
|
Adjustment
to pension and postretirement plans
|
(48 | ) | (127 | ) | (120 | ) | |||||||||
|
Net
deferred gain (loss) from cash flow hedges
|
4 | (4 | ) | (4 | ) | ||||||||||
|
Total
accumulated other comprehensive loss, end of year
|
(44 | ) | (131 | ) | (124 | ) | |||||||||
|
Total
Shareholders’ Equity
|
$ | 1,811 | $ | 2,022 | $ | 2,639 | |||||||||
See Notes
to CenterPoint Energy’s Consolidated Financial Statements
CENTERPOINT
ENERGY, INC. AND SUBSIDIARIES
(1) Background
CenterPoint
Energy, Inc. (CenterPoint Energy) is a public utility holding company.
CenterPoint Energy’s operating subsidiaries own and operate electric
transmission and distribution facilities, natural gas distribution facilities,
interstate pipelines and natural gas gathering, processing and treating
facilities. As of December 31, 2009, CenterPoint Energy’s indirect wholly
owned subsidiaries included:
|
|
•
|
CenterPoint
Energy Houston Electric, LLC (CenterPoint Houston), which engages in the
electric transmission and distribution business in a 5,000-square mile
area of the Texas Gulf Coast that includes the city of
Houston; and
|
|
|
•
|
CenterPoint
Energy Resources Corp. (CERC Corp. and, together with its subsidiaries,
CERC), which owns and operates natural gas distribution systems in six
states. Subsidiaries of CERC own interstate natural gas pipelines and gas
gathering systems and provide various ancillary services. A wholly owned
subsidiary of CERC Corp. offers variable and fixed-price physical natural
gas supplies primarily to commercial and industrial customers and electric
and gas utilities.
|
For a
description of CenterPoint Energy’s reportable business segments, see
Note 14.
(2) Summary
of Significant Accounting Policies
(a)
Use of Estimates
The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, disclosure of contingent
assets and liabilities at the date of the financial statements, and the reported
amounts of revenues and expenses during the reporting period. Actual results
could differ from those estimates.
(b)
Principles of Consolidation
The
accounts of CenterPoint Energy and its wholly owned and majority owned
subsidiaries are included in the consolidated financial statements. All
intercompany transactions and balances are eliminated in consolidation.
CenterPoint Energy uses the equity method of accounting for investments in
entities in which CenterPoint Energy has an ownership interest between 20% and
50% and exercises significant influence. CenterPoint Energy’s investments in
unconsolidated affiliates include a 50% ownership interest in Southeast Supply
Header, LLC (SESH) which owns and operates a 270-mile interstate natural gas
pipeline and a 50% interest in Waskom Gas Processing Company, a Texas general
partnership, which owns and operates a natural gas processing
plant. Other investments, excluding marketable securities, are
carried at cost. During
2009, CenterPoint Energy invested $137 million in SESH and received a capital
distribution of $23 million from SESH.
(c)
Revenues
CenterPoint
Energy records revenue for electricity delivery and natural gas sales and
services under the accrual method and these revenues are recognized upon
delivery to customers. Electricity deliveries not billed by month-end are
accrued based on daily supply volumes, applicable rates and analyses reflecting
significant historical trends and experience. Natural gas sales not billed by
month-end are accrued based upon estimated purchased gas volumes, estimated lost
and unaccounted for gas and currently effective tariff rates. The Interstate
Pipelines and Field Services business segments record revenues as transportation
and processing services are provided.
(d)
Long-lived Assets and Intangibles
CenterPoint
Energy records property, plant and equipment at historical cost. CenterPoint
Energy expenses repair and maintenance costs as incurred. Property, plant and
equipment include the following:
|
Weighted
Average
|
||||||||||||
|
Useful
Lives
|
December 31,
|
|||||||||||
|
(Years)
|
2008
|
2009
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Electric
Transmission & Distribution
|
27 | $ | 7,256 | $ | 7,325 | |||||||
|
Natural
Gas Distribution
|
31 | 3,266 | 3,436 | |||||||||
|
Competitive
Natural Gas Sales and Services
|
26 | 67 | 69 | |||||||||
|
Interstate
Pipelines
|
58 | 2,334 | 2,524 | |||||||||
|
Field
Services
|
51 | 601 | 931 | |||||||||
|
Other
property
|
26 | 482 | 485 | |||||||||
|
Total
|
14,006 | 14,770 | ||||||||||
|
Accumulated
depreciation and amortization:
|
||||||||||||
|
Electric
Transmission & Distribution
|
2,652 | 2,737 | ||||||||||
|
Natural
Gas Distribution
|
708 | 825 | ||||||||||
|
Competitive
Natural Gas Sales and Services
|
11 | 13 | ||||||||||
|
Interstate
Pipelines
|
182 | 223 | ||||||||||
|
Field
Services
|
28 | 27 | ||||||||||
|
Other
property
|
129 | 157 | ||||||||||
|
Total
accumulated depreciation and amortization
|
3,710 | 3,982 | ||||||||||
|
Property,
plant and equipment, net
|
$ | 10,296 | $ | 10,788 | ||||||||
Goodwill
by reportable business segment as of December 31, 2008 and 2009 is as
follows (in millions):
|
Natural
Gas Distribution
|
$ | 746 | ||
|
Interstate
Pipelines
|
579 | |||
|
Competitive
Natural Gas Sales and Services
|
335 | |||
|
Field
Services
|
25 | |||
|
Other
Operations
|
11 | |||
|
Total
|
$ | 1,696 |
CenterPoint
Energy performs its goodwill impairment tests at least annually and evaluates
goodwill when events or changes in circumstances indicate that its carrying
value may not be recoverable. The impairment evaluation for goodwill is
performed by using a two-step process. In the first step, the fair value of each
reporting unit is compared with the carrying amount of the reporting unit,
including goodwill. The estimated fair value of the reporting unit is generally
determined on the basis of discounted future cash flows. If the estimated fair
value of the reporting unit is less than the carrying amount of the reporting
unit, then a second step must be completed in order to determine the amount of
the goodwill impairment that should be recorded. In the second step, the implied
fair value of the reporting unit’s goodwill is determined by allocating the
reporting unit’s fair value to all of its assets and liabilities other than
goodwill (including any unrecognized intangible assets) in a manner similar to a
purchase price allocation. The resulting implied fair value of the goodwill that
results from the application of this second step is then compared to the
carrying amount of the goodwill and an impairment charge is recorded for the
difference.
CenterPoint
Energy performed the test at July 1, 2009, its annual impairment testing
date, and determined that no impairment charge for goodwill was
required.
CenterPoint
Energy periodically evaluates long-lived assets, including property, plant and
equipment, and specifically identifiable intangibles, when events or changes in
circumstances indicate that the carrying value of these assets may not be
recoverable. The determination of whether an impairment has occurred is based on
an estimate of undiscounted cash flows attributable to the assets, as compared
to the carrying value of the assets.
(e)
Regulatory Assets and Liabilities
CenterPoint
Energy applies the guidance for accounting for regulated operations, to the
Electric Transmission & Distribution business segment and the Natural
Gas Distribution business segment and to portions of the Interstate Pipelines
business segment.
The
following is a list of regulatory assets/liabilities reflected on CenterPoint
Energy’s Consolidated Balance Sheets as of December 31, 2008 and
2009:
|
December 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
(In
millions)
|
||||||||
|
Securitized
regulatory asset (1)
|
$ | 2,430 | $ | 2,886 | ||||
|
Unrecognized
equity return
|
(207 | ) | (232 | ) | ||||
|
Unamortized
loss on reacquired debt
|
73 | 67 | ||||||
|
Hurricane
Ike restoration cost (1)
|
435 | 5 | ||||||
|
Pension
and postretirement-related regulatory asset
|
848 | 781 | ||||||
|
Other
long-term regulatory assets(2)
|
105 | 170 | ||||||
|
Total
regulatory assets (1)
|
3,684 | 3,677 | ||||||
|
Estimated
removal costs
|
779 | 818 | ||||||
|
Other
long-term regulatory liabilities
|
42 | 103 | ||||||
|
Total
regulatory liabilities
|
821 | 921 | ||||||
|
Total
regulatory assets and liabilities, net
|
$ | 2,863 | $ | 2,756 | ||||
__________
|
|
(1)
|
As
discussed in Note 8(b), CenterPoint Houston securitized approximately
$665 million of Hurricane Ike restoration costs in November
2009. CenterPoint Houston did not record a return on Hurricane
Ike restoration costs until approval by the Public Utility Commission of
Texas (Texas Utility Commission) was received in 2009. Other
regulatory assets that are not earning a return were not material at
December 31, 2008 and 2009.
|
|
|
(2)
|
CenterPoint
Houston’s actuarially determined pension expense for 2009 in excess of the
2007 base year amount is being deferred for rate making purposes until its
next general rate case pursuant to Texas law. CenterPoint
Houston deferred as a regulatory asset $32 million in pension and
other postemployment expenses during the year ended December 31,
2009.
|
CenterPoint
Energy’s rate-regulated businesses recognize removal costs as a component of
depreciation expense in accordance with regulatory treatment. As of
December 31, 2008 and 2009, these removal costs of $779 million and
$818 million, respectively, are classified as regulatory liabilities in
CenterPoint Energy’s Consolidated Balance Sheets. A portion of the amount
of removal costs that related to asset retirement obligations has been
reclassified from a regulatory liability to an asset retirement liability in
accordance with accounting guidance for conditional asset retirement
obligations. At December 31, 2008 and 2009, CenterPoint Energy’s
asset retirement obligations were $63 million and $82 million,
respectively. The
increase in asset retirement obligation in 2009 of $19 million is primarily
attributable to the decrease in the credit-adjusted risk-free rate used to value
the asset retirement obligation as of the end of the period.
(f)
Depreciation and Amortization Expense
Depreciation
is computed using the straight-line method based on economic lives or
regulatory-mandated recovery periods. Amortization expense includes amortization
of regulatory assets and other intangibles. See Notes 2(e) and 3(a)
for additional discussion of these items.
The
following table presents depreciation and amortization expense for 2007, 2008
and 2009 (in millions).
|
2007
|
2008
|
2009
|
||||||||||
|
Depreciation
expense
|
$ | 455 | $ | 478 | $ | 496 | ||||||
|
Amortization
expense
|
176 | 230 | 247 | |||||||||
|
Total
depreciation and amortization expense
|
$ | 631 | $ | 708 | $ | 743 | ||||||
(g)
Capitalization of Interest and Allowance for Funds Used During
Construction
Allowance
for funds used during construction (AFUDC) represents the approximate net
composite interest cost of borrowed funds and a reasonable return on the equity
funds used for construction. Although AFUDC increases both utility plant and
earnings, it is realized in cash when the assets are included in rates for
subsidiaries that apply the guidance for accounting for regulated operations.
Interest and AFUDC are capitalized as a component of projects under construction
and will be amortized over the assets’ estimated useful lives. During 2007, 2008
and 2009, CenterPoint Energy capitalized interest and AFUDC of $21 million,
$12 million and $5 million, respectively.
(h)
Income Taxes
CenterPoint
Energy files a consolidated federal income tax return and follows a policy of
comprehensive interperiod tax allocation. CenterPoint Energy uses the asset and
liability method of accounting for deferred income taxes. Deferred income tax
assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. Investment tax
credits that were deferred are being amortized over the estimated lives of the
related property. A valuation allowance is established against deferred tax
assets for which management believes realization is not considered more likely
than not. CenterPoint Energy recognizes interest and penalties as a component of
income tax expense. For additional information regarding income taxes, see Note
9.
(i)
Accounts Receivable and Allowance for Doubtful Accounts
Accounts
receivable are net of an allowance for doubtful accounts of $35 million and
$24 million at December 31, 2008 and 2009, respectively. The provision
for doubtful accounts in CenterPoint Energy’s Statements of Consolidated Income
for 2007, 2008 and 2009 was $45 million, $54 million and
$36 million, respectively.
On
October 9, 2009, CERC amended its receivables facility to extend the termination
date to October 8, 2010. Availability under CERC’s 364-day receivables facility
ranges from $150 million to $375 million, reflecting seasonal changes
in receivables balances. At December 31, 2008 and 2009, the facility size
was $128 million and $150 million, respectively. As of December 31,
2008 and 2009, advances under the receivables facilities were $78 million
and $-0-, respectively.
(j)
Inventory
Inventory
consists principally of materials and supplies and natural gas. Materials and
supplies are valued at the lower of average cost or market. Natural gas
inventories of CenterPoint Energy’s Competitive Natural Gas Sales and Services
business segment are also primarily valued at the lower of average cost or
market. Natural gas inventories of CenterPoint Energy’s Natural Gas Distribution
business segment are primarily valued at weighted average cost. During 2008 and
2009, CenterPoint Energy recorded $30 million and $6 million,
respectively, in write-downs of natural gas inventory to the lower of average
cost or market.
|
December 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
(In
millions)
|
||||||||
|
Materials
and supplies
|
$ | 128 | $ | 138 | ||||
|
Natural
gas
|
441 | 189 | ||||||
|
Total
inventory
|
$ | 569 | $ | 327 | ||||
(k)
Derivative Instruments
CenterPoint
Energy is exposed to various market risks. These risks arise from transactions
entered into in the normal course of business. CenterPoint Energy
utilizes derivative instruments such as physical forward contracts, swaps and
options to mitigate the impact of changes in commodity prices and weather on its
operating results and cash flows. Such derivatives are recognized in CenterPoint
Energy’s Consolidated Balance Sheets at their fair value unless CenterPoint
Energy elects the normal purchase and sales exemption for qualified physical
transactions. A derivative may be designated as a normal purchase or normal sale
if the intent is to physically receive or deliver the product for use or sale in
the normal course of business.
CenterPoint
Energy has a Risk Oversight Committee composed of corporate and business segment
officers that oversees all commodity price, weather and credit risk activities,
including CenterPoint Energy’s marketing, risk management services and hedging
activities. The committee’s duties are to establish CenterPoint Energy’s
commodity risk policies, allocate board-approved commercial risk limits, approve
use of new products and commodities, monitor positions and ensure compliance
with CenterPoint Energy’s risk management policies and procedures and limits
established by CenterPoint Energy’s board of directors.
CenterPoint
Energy’s policies prohibit the use of leveraged financial instruments. A
leveraged financial instrument, for this purpose, is a transaction involving a
derivative whose financial impact will be based on an amount other than the
notional amount or volume of the instrument.
(l)
Investments in Other Debt and Equity Securities
CenterPoint
Energy reports "trading" securities at estimated fair value in its Consolidated
Balance Sheets, and any unrealized holding gains and losses are recorded as
other income (expense) in its Statements of Consolidated Income.
As of
December 31, 2008 and 2009, CenterPoint Energy held investments in Time
Warner Inc. (TW) related securities, which were classified as "trading"
securities. For information regarding these investments, see
Note 6.
(m)
Environmental Costs
CenterPoint
Energy expenses or capitalizes environmental expenditures, as appropriate,
depending on their future economic benefit. CenterPoint Energy expenses amounts
that relate to an existing condition caused by past operations that do not have
future economic benefit. CenterPoint Energy records undiscounted liabilities
related to these future costs when environmental assessments and/or remediation
activities are probable and the costs can be reasonably estimated.
(n)
Statements of Consolidated Cash Flows
For
purposes of reporting cash flows, CenterPoint Energy considers cash equivalents
to be short-term, highly liquid investments with maturities of three months or
less from the date of purchase. In connection with the issuance of transition
bonds in October 2001, December 2005 and February 2008 and system restoration
bonds in November 2009, CenterPoint Energy was required to establish restricted
cash accounts to collateralize the bonds that were issued in these financing
transactions. These restricted cash accounts are not available for withdrawal
until the maturity of the bonds and are not included in cash and cash
equivalents. These restricted cash accounts of $60 million and
$34 million at December 31, 2008 and 2009, respectively, are included
in other current assets in CenterPoint Energy's Consolidated Balance Sheets. For
additional information regarding transition and system restoration bonds, see
Notes 3(a), 3(b) and 8(b). Cash and cash equivalents includes
$166 million and $151 million at December 31, 2008 and 2009,
respectively, that is held by CenterPoint Energy’s transition and system
restoration bond subsidiaries solely to support servicing the transition and
system restoration bonds.
(o)
New Accounting Pronouncements
Effective
January 1, 2009, CenterPoint Energy adopted new accounting guidance which
requires enhanced disclosures of derivative instruments and hedging activities
such as the fair value of derivative instruments and presentation of their gains
or losses in tabular format, as well as disclosures regarding credit risks and
strategies and objectives for using derivative instruments. These
disclosures are included as part of CenterPoint Energy’s Derivatives Instruments
footnote (see Note 4).
Effective
January 1, 2009, CenterPoint Energy adopted new accounting guidance for
convertible debt instruments that may be settled in cash upon conversion
(including partial cash settlement) which changed the accounting treatment for
convertible securities that the issuer may settle fully or partially in cash and
which required retrospective application to all periods presented. Under this
new guidance, cash settled convertible securities are separated into their debt
and equity components. The value assigned to the debt component is the estimated
fair value, as of the issuance date, of a similar debt instrument without the
conversion feature, and the difference
76
between
the proceeds for the convertible debt and the amount reflected as a debt
liability is recorded as additional paid-in capital. As a result, the debt is
recorded at a discount reflecting its below-market coupon interest rate. The
debt is then subsequently accreted to its par value over its expected life, with
the rate of interest that reflects the market rate at issuance being reflected
on the income statement. CenterPoint Energy currently has no convertible debt
that is within the scope of this new guidance, but did during prior periods
presented. The required retrospective implementation of this new guidance
had a non-cash effect on net income for prior periods and the Consolidated
Balance Sheets when CenterPoint Energy had contingently convertible debt
outstanding. The effect on net income for the years ended December 31, 2007 and
2008 was a decrease in net income of $4 million, or $0.02 per basic and
diluted share, and $1 million, or $0.01 per basic share and no change per
diluted share, respectively. The implementation effect on the Consolidated
Balance Sheet as of December 31, 2008 increased Additional Paid-In-Capital and
Accumulated Deficit by $23 million.
Effective
January 1, 2009, CenterPoint Energy adopted new accounting guidance on
employers’ disclosures about postretirement benefit plan assets which expands
the disclosures about employers’ plan assets to include more detailed
disclosures about the employers’ investment strategies, major categories of plan
assets, concentrations of risk within plan assets and valuation techniques used
to measure the fair value of plan assets. See Note 2(p) below for the required
disclosures.
Effective
June 30, 2009, CenterPoint Energy adopted new accounting guidance on interim
disclosures about fair value of financial instruments which expands the fair
value disclosures required for all financial instruments to interim periods.
This new guidance also requires entities to disclose in interim periods the
methods and significant assumptions used to estimate the fair value of financial
instruments. CenterPoint Energy’s adoption of this new guidance did not have a
material impact on its financial position, results of operations or cash
flows.
Effective
June 30, 2009, CenterPoint Energy adopted new accounting guidance on subsequent
events that establishes general standards of accounting for and disclosure of
events that occur after the balance sheet date but before financial statements
are issued or are available to be issued. CenterPoint Energy’s adoption of this
new guidance did not have a material impact on its financial position, results
of operations or cash flows. See Note 15 for the subsequent event related
disclosures.
Effective
July 1, 2009, CenterPoint Energy adopted new accounting guidance on the FASB
Accounting Standards Codification (Codification) and the hierarchy of generally
accepted accounting principles. This new accounting guidance
establishes the Codification as the source of authoritative U.S. generally
accepted accounting principles recognized by the FASB to be applied by
nongovernmental entities. Rules and interpretive releases of the
Securities and Exchange Commission (SEC) under authority of federal securities
laws are also sources of authoritative GAAP for SEC
registrants. CenterPoint Energy’s adoption of this new guidance did not
have any impact on its financial position, results of operations or cash
flows.
In June
2009, the FASB issued new accounting guidance on consolidation of variable
interest entities (VIEs) that changes how a reporting entity determines a
primary beneficiary that would consolidate the VIE from a quantitative risk and
rewards approach to a qualitative approach based on which variable interest
holder has the power to direct the economic performance related activities of
the VIE as well as the obligation to absorb losses or right to receive benefits
that could potentially be significant to the VIE. This new guidance requires the
primary beneficiary assessment to be performed on an ongoing basis and also
requires enhanced disclosures that will provide more transparency about a
company’s involvement in a VIE. This new guidance is effective for a reporting
entity’s first annual reporting period that begins after November 15,
2009. CenterPoint Energy expects that the adoption of this new guidance
will not have a material impact on its financial position, results of operations
or cash flows.
In
January 2010, the FASB issued new accounting guidance to require additional fair
value related disclosures including transfers into and out of Levels 1 and 2 and
separate disclosures about purchases, sales, issuances, and settlements relating
to Level 3 measurements. It also clarifies existing fair value disclosure
guidance about the level of disaggregation and about inputs and valuation
techniques. This new guidance is effective for the first reporting period
beginning after December 15, 2009. CenterPoint Energy expects that the adoption
of this new guidance will not have a material impact on its financial position,
results of operation or cash flows.
Management
believes the impact of other recently issued standards, which are not yet
effective, will not have a material impact on CenterPoint Energy’s consolidated
financial position, results of operations or cash flows upon
adoption.
(p)
Stock-Based Incentive Compensation Plans and Employee Benefit Plans
Stock-Based
Incentive Compensation Plans
CenterPoint
Energy has long-term incentive plans (LTIPs) that provide for the issuance of
stock-based incentives, including stock options, performance awards, restricted
stock unit awards and restricted and unrestricted stock awards to officers and
key employees. Approximately 21 million shares of CenterPoint Energy
common stock are authorized to be issued under these plans.
Equity
awards are granted to employees without cost to the participants. The
performance awards granted in 2007, 2008 and 2009 are distributed based upon the
achievement of certain objectives over a three-year performance cycle. The stock
awards granted in 2007, 2008 and 2009 are subject to the operational condition
that total common dividends declared during the three-year vesting period must
be at least $2.04, $2.19 and $2.28 per share, respectively. The stock
awards generally vest at the end of a three-year period. Upon vesting, both the
performance and stock awards are issued to the participants along with the value
of dividend equivalents earned over the performance cycle or vesting period.
CenterPoint Energy issues new shares in order to satisfy share-based payments
related to LTIPs.
Stock
options are generally granted with an exercise price equal to the average of the
high and low sales price of CenterPoint Energy’s stock at the date of grant.
These stock options generally become exercisable in one-third increments on each
of the first through third anniversaries of the grant date and have 10-year
contractual terms. No stock options were granted during 2007, 2008 and
2009.
CenterPoint
Energy recorded LTIP compensation expense of $10 million, $10 million
and $15 million for the years ended December 31, 2007, 2008 and 2009,
respectively. This expense is included in Operation and Maintenance
Expense in the Statements of Consolidated Income.
The total
income tax benefit recognized related to LTIPs was $4 million,
$4 million and $6 million in the years ended December 31, 2007, 2008
and 2009, respectively. No compensation cost related to LTIPs was capitalized as
a part of inventory or fixed assets in 2007, 2008 or 2009.
The
actual tax benefit realized for tax deductions related to LTIPs totaled
$7 million, $5 million and $6 million, for 2007, 2008 and 2009,
respectively.
Compensation
costs for the performance and stock awards granted under LTIPs are measured
using fair value and expected achievement levels on the grant
date. The fair value of awards granted to employees after April 2009
are based on the closing stock price of CenterPoint Energy’s common stock on the
grant date. The fair value of awards granted prior to May 2009 are
based on the average of the high and low stock price of CenterPoint Energy’s
common stock on the grant date. The compensation expense is recorded on a
straight-line basis over the vesting period. Forfeitures are
estimated on the date of grant based on historical averages. For
performance awards with operational goals, the expected achievement level is
revised as goal achievements are evaluated.
The
following tables summarize CenterPoint Energy’s LTIP activity for
2009:
Stock
Options
|
Outstanding
Options
Year
Ended December 31, 2009
|
|||||||||||||||
|
Shares
(Thousands)
|
Weighted-Average
Exercise
Price
|
Remaining
Average
Contractual
Life
(Years)
|
Aggregate
Intrinsic
Value
(Millions)
|
||||||||||||
|
Outstanding
at December 31, 2008
|
5,856 | $ | 17.67 | ||||||||||||
|
Expired
|
(573 | ) | 18.28 | ||||||||||||
|
Cancelled
|
(295 | ) | 25.63 | ||||||||||||
|
Exercised
|
(475 | ) | 9.23 | ||||||||||||
|
Outstanding
at December 31, 2009
|
4,513 | 17.95 | 1.9 | $ | 14 | ||||||||||
|
Exercisable
at December 31, 2009
|
4,513 | 17.95 | 1.9 | 14 | |||||||||||
Cash
received from stock options exercised was $22 million, $3 million and
$4 million for 2007, 2008 and 2009, respectively.
Performance
Awards
|
Outstanding
and Non-Vested Shares
Year
Ended December 31, 2009
|
|||||||||||||||
|
Shares
(Thousands)
|
Weighted-Average
Grant
Date
Fair
Value
|
Remaining
Average
Contractual
Life
(Years)
|
Aggregate
Intrinsic
Value
(Millions)
|
||||||||||||
|
Outstanding
at December 31, 2008
|
2,102 | $ | 15.37 | ||||||||||||
|
Granted
|
1,219 | 12.42 | |||||||||||||
|
Forfeited
or cancelled
|
(222 | ) | 13.25 | ||||||||||||
|
Vested
and released to participants
|
(516 | ) | 13.08 | ||||||||||||
|
Outstanding
at December 31, 2009
|
2,583 | 14.62 |
1.2
|
$ |
28
|
||||||||||
The
non-vested and outstanding shares displayed in the table above, assumes that
shares are issued at the maximum performance level. The aggregate intrinsic
value reflects the impacts of current expectations of achievement and stock
price.
Stock
Awards
|
Outstanding
and Non-Vested Stock Shares
Year
Ended December 31, 2009
|
|||||||||||||||
|
Shares
(Thousands)
|
Weighted-Average
Grant
Date
Fair
Value
|
Remaining
Average
Contractual
Life
(Years)
|
Aggregate
Intrinsic
Value
(Millions)
|
||||||||||||
|
Outstanding
at December 31, 2008
|
789 | $ | 15.33 | ||||||||||||
|
Granted
|
460 | 12.30 | |||||||||||||
|
Forfeited
or cancelled
|
(9 | ) | 14.02 | ||||||||||||
|
Vested
and released to participants
|
(289 | ) | 13.73 | ||||||||||||
|
Outstanding
at December 31, 2009
|
951 | 14.36 |
1.3
|
$ |
14
|
||||||||||
The
weighted-average grant-date fair values of awards granted were as follows for
2007, 2008 and 2009:
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
Performance
awards
|
$ | 18.20 | $ | 15.40 | $ | 12.42 | ||||||
|
Stock
awards
|
18.29 | 15.09 | 12.30 | |||||||||
Valuation
Data
The total
intrinsic value of awards received by participants was as follows for 2007, 2008
and 2009:
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Stock
options exercised
|
$ | 13 | $ | 2 | $ | 2 | ||||||
|
Performance
awards
|
3 | 6 | 7 | |||||||||
|
Stock
awards
|
4 | 5 | 4 | |||||||||
The total
grant date fair value of performance and stock awards which vested during the
years ended December 31, 2007, 2008 and 2009 was $7 million,
$8 million and $11 million, respectively. As of
December 31, 2009, there was $27 million of total unrecognized
compensation cost related to non-vested performance and stock awards which is
expected to be recognized over a weighted-average period of
1.8 years.
Pension
and Postretirement Benefits
CenterPoint
Energy maintains a non-contributory qualified defined benefit pension plan
covering substantially all employees, with benefits determined using a cash
balance formula. Under the cash balance formula, participants accumulate a
retirement benefit based upon 5% of eligible earnings, which increased from 4%
effective January 1, 2009, and accrued interest. Prior to 1999, the pension plan
accrued benefits based on years of service, final average pay and covered
compensation. Certain employees participating in the plan as of
December 31, 1998 automatically receive the greater of the accrued benefit
calculated under the prior plan formula through 2008 or the cash balance
formula. Participants have historically been 100% vested in their benefit after
completing five years of service. Effective January 1, 2008, CenterPoint Energy
changed the vesting schedule to provide for 100% vesting after three years to
comply with the Pension Protection Act of 2006. In addition to the
non-contributory qualified defined benefit pension plan, CenterPoint Energy
maintains unfunded non-qualified benefit restoration plans which allow
participants to receive the benefits to which they would have been entitled
under CenterPoint Energy’s non-contributory pension plan except for federally
mandated limits on qualified plan benefits or on the level of compensation on
which qualified plan benefits may be calculated.
CenterPoint
Energy provides certain healthcare and life insurance benefits for retired
employees on a contributory and non-contributory basis. Employees become
eligible for these benefits if they have met certain age and service
requirements at retirement, as defined in the plans. Under plan amendments,
effective in early 1999, healthcare benefits for future retirees were changed to
limit employer contributions for medical coverage.
Such
benefit costs are accrued over the active service period of employees. The net
unrecognized transition obligation, resulting from the implementation of accrual
accounting, is being amortized over approximately 20 years.
CenterPoint
Energy’s net periodic cost includes the following components relating to
pension, including the benefit restoration plan, and postretirement
benefits:
|
Year
Ended December 31,
|
||||||||||||||||||||||||
|
2007
|
2008
|
2009
|
||||||||||||||||||||||
|
Pension
Benefits
|
Postretirement
Benefits
|
Pension
Benefits
|
Postretirement
Benefits
|
Pension
Benefits
|
Postretirement
Benefits
|
|||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||
|
Service
cost
|
$ | 37 | $ | 2 | $ | 31 | $ | 1 | $ | 25 | $ | 1 | ||||||||||||
|
Interest cost
|
100 | 26 | 101 | 27 | 113 | 28 | ||||||||||||||||||
|
Expected return on
plan assets
|
(149 | ) | (12 | ) | (147 | ) | (12 | ) | (98 | ) | (9 | ) | ||||||||||||
|
Amortization
of prior service cost
(credit)
|
(7 | ) | - | (8 | ) | 3 | 3 | 3 | ||||||||||||||||
|
Amortization of net
loss
|
34 | 3 | 23 | - | 68 | - | ||||||||||||||||||
|
Amortization of
transition obligation
|
- | 7 | - | 7 | - | 7 | ||||||||||||||||||
|
Benefit
enhancement
|
- | - | 1 | - | - | - | ||||||||||||||||||
|
Net periodic
cost
|
$ | 15 | $ | 26 | $ | 1 | $ | 26 | $ | 111 | $ | 30 | ||||||||||||
CenterPoint
Energy used the following assumptions to determine net periodic cost relating to
pension and postretirement benefits:
|
December 31,
|
||||||||||||||||||||||||
|
2007
|
2008
|
2009
|
||||||||||||||||||||||
|
Pension
Benefits
|
Postretirement
Benefits
|
Pension
Benefits
|
Postretirement
Benefits
|
Pension
Benefits
|
Postretirement
Benefits
|
|||||||||||||||||||
|
Discount
rate
|
5.85 | % | 5.85 | % | 6.40 | % | 6.40 | % | 6.90 | % | 6.90 | % | ||||||||||||
|
Expected
return on plan assets
|
8.50 | 7.60 | 8.50 | 7.60 | 8.00 | 7.05 | ||||||||||||||||||
|
Rate
of increase in compensation levels
|
4.60 | - | 4.60 | - | 4.60 | - | ||||||||||||||||||
In
determining net periodic benefits cost, CenterPoint Energy uses fair value, as
of the beginning of the year, as its basis for determining expected return on
plan assets.
The
following table summarizes changes in the benefit obligation, plan assets, the
amounts recognized in consolidated balance sheets and the key assumptions of
CenterPoint Energy’s pension, including benefit restoration, and postretirement
plans. The measurement dates for plan assets and obligations were
December 31, 2008 and 2009.
|
December 31,
|
||||||||||||||||
|
2008
|
2009
|
|||||||||||||||
|
Pension
Benefits
|
Postretirement
Benefits
|
Pension
Benefits
|
Postretirement
Benefits
|
|||||||||||||
|
(In
millions, except for actuarial assumptions)
|
||||||||||||||||
|
Change
in Benefit Obligation
|
||||||||||||||||
|
Benefit
obligation, beginning of year
|
$ | 1,645 | $ | 437 | $ | 1,710 | $ | 426 | ||||||||
|
Service
cost
|
31 | 1 | 25 | 1 | ||||||||||||
|
Interest
cost
|
101 | 27 | 113 | 28 | ||||||||||||
|
Participant
contributions
|
- | 5 | - | 6 | ||||||||||||
|
Benefits
paid
|
(123 | ) | (38 | ) | (111 | ) | (42 | ) | ||||||||
|
Actuarial
gain (loss)
|
(59 | ) | (10 | ) | 129 | 29 | ||||||||||
|
Plan
amendment
|
114 | - | - | - | ||||||||||||
|
Medicare
reimbursement
|
- | 4 | - | 2 | ||||||||||||
|
Benefit
enhancement
|
1 | - | - | - | ||||||||||||
|
Benefit
obligation, end of year
|
1,710 | 426 | 1,866 | 450 | ||||||||||||
|
Change
in Plan Assets
|
||||||||||||||||
|
Fair
Value of plan assets, beginning of year
|
1,792 | 161 | 1,276 | 135 | ||||||||||||
|
Employer
contributions
|
8 | 27 | 20 | 28 | ||||||||||||
|
Participant
contributions
|
- | 5 | - | 6 | ||||||||||||
|
Benefits
paid
|
(123 | ) | (38 | ) | (111 | ) | (42 | ) | ||||||||
|
Actual
investment return
|
(401 | ) | (20 | ) | 247 | 19 | ||||||||||
|
Fair
value of plan assets, end of year
|
1,276 | 135 | 1,432 | 146 | ||||||||||||
|
Funded
status, end of year
|
$ | (434 | ) | $ | (291 | ) | $ | (434 | ) | $ | (304 | ) | ||||
|
Amounts
Recognized in Balance Sheets
|
||||||||||||||||
|
Current
liabilities-other
|
$ | (9 | ) | $ | (10 | ) | $ | (9 | ) | $ | (9 | ) | ||||
|
Other
liabilities-benefit obligations
|
(425 | ) | (281 | ) | (425 | ) | (295 | ) | ||||||||
|
Net
liability, end of year
|
$ | (434 | ) | $ | (291 | ) | $ | (434 | ) | $ | (304 | ) | ||||
|
Actuarial
Assumptions
|
||||||||||||||||
|
Discount
rate
|
6.90 | % | 6.90 | % | 5.70 | % | 5.70 | % | ||||||||
|
Expected
return on plan assets
|
8.00 | 7.05 | 8.00 | 7.05 | ||||||||||||
|
Rate
of increase in compensation levels
|
4.60 | - | 4.60 | - | ||||||||||||
|
Healthcare
cost trend rate assumed for the next year
|
- | 6.50 | - | 7.50 | ||||||||||||
|
Prescription
drug cost trend rate assumed for the next year
|
- | 12.00 | - | 8.00 | ||||||||||||
|
Rate
to which the cost trend rate is assumed to decline (the ultimate trend
rate)
|
- | 5.50 | - | 5.50 | ||||||||||||
|
Year
that the healthcare rate reaches the ultimate trend rate
|
- | 2011 | - | 2014 | ||||||||||||
|
Year
that the prescription drug rate reaches the ultimate trend
rate
|
- | 2014 | - | 2015 | ||||||||||||
At
December 31, 2008, the pension benefit obligation increased by $114 million due to a plan
amendment effective January 1, 2009. The amendment increased certain cash
balance accounts in conjunction with a transition to a uniform cash balance
program effective 2009.
The
accumulated benefit obligation for all defined benefit pension plans was
$1,708 million and $1,864 million as of December 31, 2008 and
2009, respectively.
The
expected rate of return assumption was developed by a weighted-average return
analysis of the targeted asset allocation of CenterPoint Energy’s plans and the
expected real return for each asset class, based on the long-term capital market
assumptions, adjusted for investment fees and diversification effects, in
addition to expected inflation.
The
discount rate assumption was determined by matching the accrued cash flows of
CenterPoint Energy’s plans against a hypothetical yield curve of high-quality
corporate bonds represented by a series of annualized individual discount rates
from one-half to thirty years.
For
measurement purposes, healthcare costs are assumed to increase 7.50% during
2010, after which this rate decreases until reaching the ultimate trend rate of
5.50% in 2014. Prescription drug costs are assumed to increase 8.00% during
2010, after which this rate decreases until reaching the ultimate trend rate of
5.50% in 2015.
Amounts
recognized in accumulated other comprehensive loss consist of the
following:
|
December 31,
|
||||||||||||||||
|
2008
|
2009
|
|||||||||||||||
|
Pension
Benefits
|
Postretirement
Benefits
|
Pension
Benefits
|
Postretirement
Benefits
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Unrecognized
actuarial loss
|
$ | 181 | $ | 5 | $ | 162 | $ | 15 | ||||||||
|
Unrecognized
prior service cost
|
17 | 11 | 16 | 9 | ||||||||||||
|
Unrecognized
transition obligation
|
- | 3 | - | 3 | ||||||||||||
|
Net
amount recognized in accumulated other comprehensive loss
|
$ | 198 | $ | 19 | $ | 178 | $ | 27 | ||||||||
The
changes in plan assets and benefit obligations recognized in other comprehensive
income during 2009 are as follows (in millions):
|
Pension
Benefits
|
Postretirement
Benefits
|
|||||||
|
Net
loss (gain)
|
$ | (34 | ) | $ | 10 | |||
|
Amortization
of net loss
|
15 | - | ||||||
|
Prior
service credit
|
(2 | ) | (4 | ) | ||||
|
Amortization
of prior service credit (cost)
|
1 | 2 | ||||||
|
Total
recognized in comprehensive income
|
$ | (20 | ) | $ | 8 | |||
The total
expense recognized in net periodic costs and other comprehensive income was
$91 million and $38 million for pension and postretirement benefits,
respectively, for the year ended December 31, 2009.
The
amounts in accumulated other comprehensive loss expected to be recognized as
components of net periodic benefit cost during 2010 are as follows (in
millions):
|
Pension
Benefits
|
Postretirement
Benefits
|
|||||||
|
Unrecognized
actuarial loss
|
$ | 13 | $ | - | ||||
|
Unrecognized
prior service cost
|
1 | 2 | ||||||
|
Amounts
in comprehensive income to be recognized in net periodic cost in 2010
|
$ | 14 | $ | 2 | ||||
The
following table displays pension benefits related to CenterPoint Energy’s
pension plans that have accumulated benefit obligations in excess of plan
assets:
|
December 31,
|
||||||||||||||||
|
2008
|
2009
|
|||||||||||||||
|
Pension
Qualified
|
Pension
Non-qualified
|
Pension
Qualified
|
Pension
Non-qualified
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Accumulated
benefit obligation
|
$ | 1,622 | $ | 86 | $ | 1,770 | $ | 94 | ||||||||
|
Projected
benefit obligation
|
1,624 | 86 | 1,772 | 94 | ||||||||||||
|
Fair
value of plan assets
|
1,276 | - | 1,432 | - | ||||||||||||
Assumed
healthcare cost trend rates have a significant effect on the reported amounts
for CenterPoint Energy’s postretirement benefit plans. A 1% change in the
assumed healthcare cost trend rate would have the following
effects:
|
1%
Increase
|
1%
Decrease
|
|||||||
|
(In
millions)
|
||||||||
|
Effect
on the postretirement benefit obligation
|
$ | 17 | $ | 15 | ||||
|
Effect
on total of service and interest cost
|
1 | 1 | ||||||
In
managing the investments associated with the benefit plans, CenterPoint Energy’s
objective is to preserve and enhance the value of plan assets while maintaining
an acceptable level of volatility. These objectives are expected to be achieved
through an investment strategy that manages liquidity requirements while
maintaining a long-term horizon in making investment decisions and efficient and
effective management of plan assets.
As part
of the investment strategy discussed above, CenterPoint Energy has adopted and
maintains the following weighted average allocation targets for its benefit
plans:
|
Pension
Benefits
|
Postretirement
Benefits
|
|||||||
|
Domestic
equity securities
|
25-35 | % | 21-31 | % | ||||
|
Global
equity securities
|
7-13 | % | - | |||||
|
International
equity securities
|
17-23 | % | 4-14 | % | ||||
|
Debt
securities
|
30-40 | % | 60-70 | % | ||||
|
Real
estate
|
0-5 | % | - | |||||
|
Cash
|
0-2 | % | 0-2 | % | ||||
The fair
values of CenterPoint Energy’s pension plan assets at December 31, 2009, by
asset category are as follows:
|
Fair
Value Measurements at December 31, 2009
(in
millions)
|
||||||||||||||||
|
Total
|
Quoted
Prices in
Active
Markets for
Identical
Assets
(Level
1)
|
Significant
Observable
Inputs
(Level
2)
|
Significant
Unobservable
Inputs
(Level
3)
|
|||||||||||||
|
Cash
|
$ | 11 | $ | 11 | $ | - | $ | - | ||||||||
|
Common
collective trust funds (1)
|
733 | - | 733 | - | ||||||||||||
|
Corporate
Bonds:
|
||||||||||||||||
|
Investment
grade or above
|
193 | - | 192 | 1 | ||||||||||||
|
High
yield
|
2 | - | 2 | |||||||||||||
|
Equity
securities:
|
||||||||||||||||
|
International
companies
|
162 | 160 | 2 | - | ||||||||||||
|
U.S.
companies
|
96 | 96 | - | - | ||||||||||||
|
Securities
received as collateral
|
114 | 114 | - | - | ||||||||||||
|
U.S.
government back agencies bonds
|
55 | 55 | - | - | ||||||||||||
|
U.S.
treasuries
|
50 | 50 | - | - | ||||||||||||
|
Mortgage
backed securities
|
39 | - | 39 | - | ||||||||||||
|
Asset
backed securities
|
27 | - | 24 | 3 | ||||||||||||
|
Municipal
bonds
|
22 | 2 | 20 | - | ||||||||||||
|
Mutual
funds (2)
|
21 | 21 | - | - | ||||||||||||
|
International
government bonds
|
12 | - | 12 | - | ||||||||||||
|
Real
estate
|
9 | - | - | 9 | ||||||||||||
|
Obligation
to return securities received as collateral
|
(114 | ) | (114 | ) | - | - | ||||||||||
|
Total
|
$ | 1,432 | $ | 395 | $ | 1,024 | $ | 13 | ||||||||
|
|
(1)
|
30%
of the amount invested in common collective trust funds is in fixed income
securities, 31% is in U.S. equities and 39% is in international
equities.
|
|
|
(2)
|
48%
of the amount invested in mutual funds is in fixed income securities and
52% is in U.S. equities.
|
The
pension plan utilized both exchange traded and over-the-counter financial
instruments such as futures, interest rate options and swaps that were marked to
market daily with the gains/losses settled in the cash accounts. The pension
plan did not include any holdings of CenterPoint Energy common stock as of
December 31, 2008 or 2009.
The
following table sets forth a summary of changes in the fair value of the pension
plan’s level 3 investments for the year ended December 31, 2009:
|
Level
3 Investments
|
||||||||||||||||
|
Year
Ended December 31, 2009
(in
millions)
|
||||||||||||||||
|
Corporate
bonds
|
Asset
backed
securities
|
Real
estate
|
Total
|
|||||||||||||
|
Balance,
beginning of year
|
$ | 1 | $ | 3 | $ | 14 | $ | 18 | ||||||||
|
Unrealized
gains/(losses) relating to
instruments
still held at the reporting date
|
- | - | (5 | ) | (5 | ) | ||||||||||
|
Balance,
end of year
|
$ | 1 | $ | 3 | $ | 9 | $ | 13 | ||||||||
The fair
values of CenterPoint Energy’s postretirement plan assets at December 31, 2009,
by asset category are as follows:
|
Fair
Value Measurements at December 31, 2009
(in
millions)
|
||||||||||||||||
|
Total
|
Quoted
Prices
in
Active
Markets
for
Identical
Assets
(Level
1)
|
Significant
Observable
Input
(Level
2)
|
Significant
Unobservable
Inputs
(Level
3)
|
|||||||||||||
|
Mutual
funds (1)
|
$ | 146 | $ | 146 | $ | - | $ | - | ||||||||
|
Total
|
$ | 146 | $ | 146 | $ | - | $ | - | ||||||||
|
|
(1)
|
65%
of the amount invested in mutual funds is in fixed income securities, 26%
is in U.S. equities and 9% is in international
equities.
|
CenterPoint
Energy contributed $13 million, $7 million and $26 million to its
qualified pension, non-qualified pension and postretirement benefits plans,
respectively, in 2009. CenterPoint Energy expects to contribute approximately
$9 million and $19 million to its non-qualified pension and
postretirement benefits plans, respectively, in 2010.
The
following benefit payments are expected to be paid by the pension and
postretirement benefit plans (in millions):
|
Postretirement
Benefit Plan
|
||||||||||||
|
Pension
Benefits
|
Benefit
Payments
|
Medicare
Subsidy
Receipts
|
||||||||||
|
2010
|
$ | 136 | $ | 33 | $ | (4 | ) | |||||
|
2011
|
138 | 35 | (5 | ) | ||||||||
|
2012
|
142 | 36 | (5 | ) | ||||||||
|
2013
|
145 | 38 | (6 | ) | ||||||||
|
2014
|
144 | 39 | (6 | ) | ||||||||
|
2015-2019
|
743 | 216 | (38 | ) | ||||||||
Savings
Plan
CenterPoint
Energy has a tax-qualified employee savings plan that includes a cash or
deferred arrangement under Section 401(k) of the Internal Revenue Code of
1986, as amended (the Code), and an employee stock ownership plan (ESOP) under
Section 4975(e)(7) of the Code. Under the plan, participating employees may
contribute a portion of their compensation, on a pre-tax or after-tax basis,
generally up to a maximum of 50% of eligible compensation. The Company matches
100% of the first 6% of each employee’s compensation contributed. The matching
contributions are fully vested at all times.
Participating
employees may elect to invest all or a portion of their contributions to the
plan in CenterPoint Energy common stock, to have dividends reinvested in
additional shares or to receive dividend payments in cash on any investment in
CenterPoint Energy common stock, and to transfer all or part of their investment
in CenterPoint Energy common stock to other investment options offered by the
plan.
The
savings plan has significant holdings of CenterPoint Energy common stock. As of
December 31, 2009, 21,320,436 shares of CenterPoint Energy’s common stock
were held by the savings plan, which represented approximately 23% of its
investments. Given the concentration of the investments in CenterPoint Energy’s
common stock, the savings plan and its participants have market risk related to
this investment.
CenterPoint
Energy’s savings plan benefit expenses were $35 million, $39 million
and $31 million in 2007, 2008 and 2009, respectively.
Postemployment
Benefits
CenterPoint
Energy provides postemployment benefits for former or inactive employees, their
beneficiaries and covered dependents, after employment but before retirement
(primarily healthcare and life insurance benefits for participants in the
long-term disability plan). The Company recorded postemployment benefit income
of $2 million, $1 million and $-0- in 2007, 2008 and 2009,
respectively.
Included
in "Benefit Obligations" in the accompanying Consolidated Balance Sheets at
December 31, 2008 and 2009 was $32 million and $29 million,
respectively, relating to postemployment obligations.
Other
Non-Qualified Plans
CenterPoint
Energy has non-qualified deferred compensation plans that provide benefits
payable to directors, officers and certain key employees or their designated
beneficiaries at specified future dates, upon termination, retirement or death.
Benefit payments are made from the general assets of CenterPoint Energy. During
2007, 2008 and 2009, CenterPoint Energy recorded benefit expense relating to
these plans of $7 million, $4 million and $6 million,
respectively. Included in "Benefit Obligations" in the accompanying Consolidated
Balance Sheets at December 31, 2008 and 2009 was $83 million and
$79 million, respectively, relating to deferred compensation
plans.
Effective
January 1, 2008, CenterPoint Energy adopted new guidance on accounting for
deferred compensation and postretirement benefit aspects of endorsement
split-dollar life insurance arrangements which required CenterPoint Energy to
recognize the effect of implementation through a cumulative effect adjustment to
retained earnings or other components of equity as of the beginning of the year
of adoption. CenterPoint Energy calculated the impact as negligible at the
time of adoption on January 1, 2008. During 2009, CenterPoint Energy
determined that its adoption calculation had omitted the impact that increasing
future premium costs would have on the liability and, therefore, it recorded as
a cumulative effect adjustment a $15 million correction to increase other
non-current liabilities and accumulated deficit as of January 1,
2008. The effect of the correction is not material to CenterPoint
Energy’s previously issued financial statements and did not affect CenterPoint
Energy’s results of operations or cash flows. Included in Benefit
Obligations in CenterPoint Energy’s Consolidated Balance Sheets at December 31,
2008 and 2009 was $16 million and $19 million, respectively, relating
to split-dollar life insurance arrangements.
Change
in Control Agreements and Other Employee Matters
CenterPoint
Energy has agreements with certain of its officers that generally provide, to
the extent applicable, in the case of a change in control of CenterPoint Energy
and termination of employment, for severance benefits of up to three times
annual base salary plus bonus, and other benefits. These agreements are for a
one-year term with automatic renewal unless action is taken by CenterPoint
Energy’s board of directors prior to the renewal.
As of
December 31, 2009, approximately 30% of CenterPoint Energy’s employees are
subject to collective bargaining agreements. One of the collective bargaining
agreements covering approximately 14% of CenterPoint Energy’s employees, the
International Brotherhood of Electrical Workers Union Local No. 66, is scheduled
to expire in May 2010. CenterPoint Energy has a good relationship with this
bargaining unit and expects to negotiate a new agreement in 2010.
(3) Regulatory
Matters
(a)
Hurricane Ike
CenterPoint
Houston’s electric delivery system suffered substantial damage as a result of
Hurricane Ike, which struck the upper Texas coast in
September 2008.
As is
common with electric utilities serving coastal regions, the poles, towers,
wires, street lights and pole mounted equipment that comprise CenterPoint
Houston’s transmission and distribution system are not covered by property
insurance, but office buildings and warehouses and their contents and
substations are covered by insurance
that
provides for a maximum deductible of $10 million. Current estimates are
that total losses to property covered by this insurance were approximately
$30 million.
CenterPoint
Houston deferred the uninsured system restoration costs as management believed
it was probable that such costs would be recovered through the regulatory
process. As a result, system restoration costs did not affect CenterPoint
Energy’s or CenterPoint Houston’s reported operating income for 2008 or
2009.
Legislation
enacted by the Texas Legislature in April 2009 authorized the Texas Utility
Commission to conduct proceedings to determine the amount of system restoration
costs and related costs associated with hurricanes or other major storms that
utilities are entitled to recover, and to issue financing orders that would
permit a utility like CenterPoint Houston to recover the distribution portion of
those costs and related carrying costs through the issuance of non-recourse
system restoration bonds similar to the securitization bonds issued
previously. The legislation also allowed such a utility to recover,
or defer for future recovery, the transmission portion of its system restoration
costs through the existing mechanisms established to recover transmission
costs.
Pursuant
to such legislation, CenterPoint Houston filed with the Texas Utility Commission
an application for review and approval for recovery of approximately
$678 million, including approximately $608 million in system
restoration costs identified as of the end of February 2009, plus
$2 million in regulatory expenses, $13 million in certain debt
issuance costs and $55 million in incurred and projected carrying costs
calculated through August 2009. In July 2009, CenterPoint Houston announced
a settlement agreement with the parties to the proceeding. Under that
settlement agreement, CenterPoint Houston was entitled to recover a total of
$663 million in costs relating to Hurricane Ike, along with carrying costs from September 1,
2009 until system restoration bonds were issued. The Texas Utility Commission
issued an order in August 2009 approving CenterPoint Houston’s application and
the settlement agreement and authorizing recovery of $663 million, of which
$643 million was attributable to distribution service and eligible for
securitization and the remaining $20 million was attributable to
transmission service and eligible for recovery through the existing mechanisms
established to recover transmission costs.
In July
2009, CenterPoint Houston filed with the Texas Utility Commission its
application for a financing order to recover the portion of approved costs
related to distribution service through the issuance of system restoration
bonds. In August 2009, the Texas Utility Commission issued a
financing order allowing CenterPoint Houston to securitize $643 million in
distribution service costs plus carrying charges from September 1, 2009
through the date the system restoration bonds were issued, as well as certain
up-front qualified costs capped at approximately $6 million. In
November 2009, CenterPoint Houston issued approximately $665 million of
system restoration bonds through its CenterPoint Energy Restoration Bond
Company, LLC subsidiary with interest rates of 1.833% to 4.243% and final
maturity dates ranging from February 2016 to August 2023. The bonds
will be repaid over time through a charge imposed on customers.
In
accordance with the financing order, CenterPoint Houston also placed a separate
customer credit in effect when the storm restoration bonds were
issued. That credit (ADFIT Credit) is applied to customers’ bills
while the bonds are outstanding to reflect the benefit of accumulated deferred
federal income taxes (ADFIT) associated with the storm restoration costs
(including a carrying charge of 11.075%). The beginning balance of the ADFIT
related to storm restoration costs was approximately $207 million and will
decline over the life of the system restoration bonds as taxes are paid on the
system restoration tariffs. The ADFIT Credit will reduce operating income in
2010 by approximately $24 million.
In
accordance with the orders discussed above, as of December 31, 2009, CenterPoint
Houston has recorded $651 million associated with distribution-related
storm restoration costs as a net regulatory asset and $20 million
associated with transmission-related storm restoration costs, of which
$18 million is recorded in property, plant and equipment and
$2 million of related carrying costs is recorded in regulatory
assets. These amounts reflect carrying costs of
$60 million related to distribution and $2 million related to
transmission through December 31, 2009, based on the 11.075% cost of
capital approved by the Texas Utility Commission. The carrying costs have
been bifurcated into two components: (i) return of borrowing costs and (ii) an
allowance for earnings on shareholders’ investment. During the year ended
December 31, 2009, the component representing a return of borrowing costs of
$23 million has been recognized and is included in other income in
CenterPoint Energy’s Statements of Consolidated Income. The component
representing an allowance for earnings on shareholders’ investment of
$39 million is being deferred and will be recognized as it is collected
through rates.
(b)
Recovery of True-Up Balance
In March
2004, CenterPoint Houston filed its true-up application with the Texas Utility
Commission, requesting recovery of $3.7 billion, excluding interest, as
allowed under the Texas Electric Choice Plan (Texas electric restructuring law).
In December 2004, the Texas Utility Commission issued its final order (True-Up
Order) allowing CenterPoint Houston to recover a true-up balance of
approximately $2.3 billion, which included interest through August 31,
2004, and provided for adjustment of the amount to be recovered to include
interest on the balance until recovery, along with the principal portion of
additional excess mitigation credits (EMCs) returned to customers after
August 31, 2004 and certain other adjustments.
CenterPoint
Houston and other parties filed appeals of the True-Up Order to a district court
in Travis County, Texas. In August 2005, that court issued its judgment on the
various appeals. In its judgment, the district court:
|
|
•
|
reversed
the Texas Utility Commission’s ruling that had denied recovery of a
portion of the capacity auction true-up
amounts;
|
|
|
•
|
reversed
the Texas Utility Commission’s ruling that precluded CenterPoint Houston
from recovering the interest component of the EMCs paid to retail electric
providers (REPs); and
|
|
|
•
|
affirmed
the True-Up Order in all other
respects.
|
The
district court’s decision would have had the effect of restoring approximately
$650 million, plus interest, of the $1.7 billion the Texas Utility
Commission had disallowed from CenterPoint Houston’s initial
request.
CenterPoint
Houston and other parties appealed the district court’s judgment to the Texas
Third Court of Appeals, which issued its decision in December 2007. In its
decision, the court of appeals:
|
|
•
|
reversed
the district court’s judgment to the extent it restored the capacity
auction true-up amounts;
|
|
|
•
|
reversed
the district court’s judgment to the extent it upheld the Texas Utility
Commission’s decision to allow CenterPoint Houston to recover EMCs paid to
RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant
Resources, Inc.);
|
|
|
•
|
ordered
that the tax normalization issue described below be remanded to the Texas
Utility Commission as requested by the Texas Utility Commission;
and
|
|
|
•
|
affirmed
the district court’s judgment in all other
respects.
|
In April
2008, the court of appeals denied all motions for rehearing and reissued
substantially the same opinion as it had rendered in December 2007.
In June
2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the
court of appeals decision. In its petition, CenterPoint Houston seeks reversal
of the parts of the court of appeals decision that (i) denied recovery of EMCs
paid to RRI, (ii) denied recovery of the capacity auction true-up amounts
allowed by the district court, (iii) affirmed the Texas Utility Commission’s
rulings that denied recovery of approximately $378 million related to
depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit
CenterPoint Houston to utilize the partial stock valuation methodology for
determining the market value of its former generation assets. Two other
petitions for review were filed with the Texas Supreme Court by other parties to
the appeal. In those petitions parties contend that (i) the Texas Utility
Commission was without authority to fashion the methodology it used for valuing
the former generation assets after it had determined that CenterPoint Houston
could not use the partial stock valuation method, (ii) in fashioning the method
it used for valuing the former generating assets, the Texas Utility Commission
deprived parties of their due process rights and an opportunity to be heard,
(iii) the net book value of the generating assets should have been adjusted
downward due to the impact of a purchase option that had been granted to RRI,
(iv) CenterPoint Houston should not have been permitted to recover construction
work in progress balances without proving those amounts in the manner required
by law and (v) the Texas Utility Commission was without authority to award
interest on the capacity auction true up award.
In June
2009, the Texas Supreme Court granted the petitions for review of the court of
appeals decision. Oral argument before the court was held in October
2009. Although CenterPoint Energy and CenterPoint Houston believe
that CenterPoint Houston’s true-up request is consistent with applicable
statutes and regulations and, accordingly, that it is reasonably possible that
it will be successful in its appeal to the Texas Supreme Court, CenterPoint
Energy can provide no assurance as to the ultimate court rulings on the issues
to be considered in the appeal or with respect to the ultimate decision by the
Texas Utility Commission on the tax normalization issue described
below.
To
reflect the impact of the True-Up Order, in 2004 and 2005, CenterPoint Energy
recorded a net after-tax extraordinary loss of $947 million. No amounts
related to the district court’s judgment or the decision of the court of appeals
have been recorded in CenterPoint Energy’s consolidated financial statements.
However, if the court of appeals decision is not reversed or modified as a
result of further review by the Texas Supreme Court, CenterPoint Energy
anticipates that it would be required to record an additional loss to reflect
the court of appeals decision. The amount of that loss would depend on several
factors, including ultimate resolution of the tax normalization issue described
below and the calculation of interest on any amounts CenterPoint Houston
ultimately is authorized to recover or is required to refund beyond the amounts
recorded based on the True-Up Order, but could range from $180 million to
$410 million (pre-tax) plus interest subsequent to December 31,
2009.
In the
True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s
stranded cost recovery by approximately $146 million, which was included in
the extraordinary loss discussed above, for the present value of certain
deferred tax benefits associated with its former electric generation assets.
CenterPoint Energy believes that the Texas Utility Commission based its order on
proposed regulations issued by the Internal Revenue Service (IRS) in March 2003
that would have allowed utilities owning assets that were deregulated before
March 4, 2003 to make a retroactive election to pass the benefits of
Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal
Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew
those proposed normalization regulations and, in March 2008, adopted final
regulations that would not permit utilities like CenterPoint Houston to pass the
tax benefits back to customers without creating normalization violations. In
addition, CenterPoint Energy received a Private Letter Ruling (PLR) from the IRS
in August 2007, prior to adoption of the final regulations, that confirmed that
the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded
cost recovery by $146 million for ADITC and EDFIT would cause normalization
violations with respect to the ADITC and EDFIT.
If the
Texas Utility Commission’s order relating to the ADITC reduction is not reversed
or otherwise modified on remand so as to eliminate the normalization violation,
the IRS could require CenterPoint Energy to pay an amount equal to CenterPoint
Houston’s unamortized ADITC balance as of the date that the normalization
violation is deemed to have occurred. In addition, the IRS could deny
CenterPoint Houston the ability to elect accelerated tax depreciation benefits
beginning in the taxable year that the normalization violation is deemed to have
occurred. Such treatment, if required by the IRS, could have a material adverse
impact on CenterPoint Energy’s results of operations, financial condition and
cash flows in addition to any potential loss resulting from final resolution of
the True-Up Order. In its opinion, the court of appeals ordered that this issue
be remanded to the Texas Utility Commission, as that commission requested. No
party has challenged that order by the court of appeals although the Texas
Supreme Court has the authority to consider all aspects of the rulings above,
not just those challenged specifically by the appellants. CenterPoint Energy and
CenterPoint Houston will continue to pursue a favorable resolution of this issue
through the appellate and administrative process. Although the Texas Utility
Commission has not previously required a company subject to its jurisdiction to
take action that would result in a normalization violation, no prediction can be
made as to the ultimate action the Texas Utility Commission may take on this
issue on remand.
The Texas
electric restructuring law allowed the amounts awarded to CenterPoint Houston in
the Texas Utility Commission’s True-Up Order to be recovered either through
securitization or through implementation of a competition transition charge
(CTC) or both. Pursuant to a financing order issued by the Texas Utility
Commission in March 2005 and affirmed by a Travis County district court, in
December 2005, a new special purpose subsidiary of CenterPoint Houston issued
$1.85 billion in transition bonds with interest rates ranging from 4.84% to
5.30% and final maturity dates ranging from February 2011 to August 2020.
Through issuance of the transition bonds,
CenterPoint
Houston recovered approximately $1.7 billion of the true-up balance
determined in the True-Up Order plus interest through the date on which the
bonds were issued.
In July
2005, CenterPoint Houston received an order from the Texas Utility Commission
allowing it to implement a CTC designed to collect the remaining
$596 million from the True-Up Order over 14 years plus interest at an
annual rate of 11.075% (CTC Order). The CTC Order authorized CenterPoint Houston
to impose a charge on REPs to recover the portion of the true-up balance not
recovered through a financing order. The CTC Order also allowed CenterPoint
Houston to collect approximately $24 million of rate case expenses over
three years without a return through a separate tariff rider (Rider RCE).
CenterPoint Houston implemented the CTC and Rider RCE effective
September 13, 2005 and began recovering approximately $620 million.
The return on the CTC portion of the true-up balance was included in CenterPoint
Houston’s tariff-based revenues beginning September 13, 2005. Effective
August 1, 2006, the interest rate on the unrecovered balance of the CTC was
reduced from 11.075% to 8.06% pursuant to a revised rule adopted by the Texas
Utility Commission in June 2006. Recovery of rate case expenses under Rider RCE
was completed in September 2008.
Certain
parties appealed the CTC Order to a district court in Travis County. In May
2006, the district court issued a judgment reversing the CTC Order in three
respects. First, the court ruled that the Texas Utility Commission had
improperly relied on provisions of its rule dealing with the interest rate
applicable to CTC amounts. The district court reached that conclusion based on
its belief that the Texas Supreme Court had previously invalidated that entire
section of the rule. The 11.075% interest rate in question was applicable from
the implementation of the CTC Order on September 13, 2005 until
August 1, 2006, the effective date of the implementation of a new CTC in
compliance with the revised rule discussed above. Second, the district court
reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston
to recover through Rider RCE the costs (approximately $5 million) for a
panel appointed by the Texas Utility Commission in connection with the valuation
of electric generation assets. Finally, the district court accepted the
contention of one party that the CTC should not be allocated to retail customers
that have switched to new on-site generation. The Texas Utility Commission and
CenterPoint Houston appealed the district court’s judgment to the Texas
Third Court of Appeals, and in July 2008, the court of appeals reversed the
district court’s judgment in all respects and affirmed the Texas Utility
Commission’s order. Two parties appealed the court of appeals decision to the
Texas Supreme Court which heard oral argument in October 2009. The ultimate
outcome of this matter cannot be predicted at this time. However, CenterPoint
Energy does not expect the disposition of this matter to have a material adverse
effect on CenterPoint Energy’s or CenterPoint Houston’s financial condition,
results of operations or cash flows.
During
the 2007 legislative session, the Texas legislature amended statutes prescribing
the types of true-up balances that can be securitized by utilities and
authorized the issuance of transition bonds to recover the balance of the CTC.
In June 2007, CenterPoint Houston filed a request with the Texas Utility
Commission for a financing order that would allow the securitization of the
remaining balance of the CTC, adjusted to refund certain unspent environmental
retrofit costs and to recover the amount of the final fuel reconciliation
settlement. CenterPoint Houston reached substantial agreement with other parties
to this proceeding, and a financing order was approved by the Texas Utility
Commission in September 2007. In February 2008, pursuant to the financing order,
a new special purpose subsidiary of CenterPoint Houston issued approximately
$488 million of transition bonds in two tranches with interest rates of
4.192% and 5.234% and final maturity dates of February 2020 and February 2023,
respectively. Contemporaneously with the issuance of those bonds, the CTC was
terminated and a transition charge was implemented. During the years ended
December 31, 2007 and 2008, CenterPoint Houston recognized approximately
$42 million and $5 million, respectively, in operating income from the
CTC.
As of
December 31, 2009, CenterPoint Energy has not recognized an allowed equity
return of $193 million on CenterPoint Houston’s true-up balance because
such return will be recognized as it is recovered in rates. During the years
ended December 31, 2007, 2008 and 2009, CenterPoint Houston recognized
approximately $14 million, $13 million and $13 million,
respectively, of the allowed equity return not previously
recognized.
(c)
Rate Proceedings
Texas. In March 2008, the
natural gas distribution businesses of CERC (Gas Operations) filed a request to
change its rates with the Railroad Commission of Texas (Railroad Commission) and
the 47 cities in its Texas Coast service territory, an area consisting of
approximately 230,000 customers in cities and communities on the outskirts
of
90
Houston.
In 2008, Gas Operations implemented rates increasing annual revenues by
approximately $3.5 million. The implemented rates were contested by 9
cities in an appeal to the 353rd District Court in Travis County, Texas. In
January 2010, that court reversed the Railroad Commission’s order in part and
remanded the matter to the Railroad Commission. The court concluded that
the Railroad Commission did not have statutory authority to impose on the
complaining cities the cost of service adjustment mechanism which the Railroad
Commission had approved in its order. Certain parties filed a motion to
modify the district court’s judgment and a final decision is not expected until
April 2010. CenterPoint Energy and CERC do not expect the outcome of this
matter to have a material adverse impact on the financial condition, results of
operations or cash flows of either CenterPoint Energy or
CERC.
In July
2009, Gas Operations filed a request to change its rates with the Railroad
Commission and the 29 cities in its Houston service territory, consisting of
approximately 940,000 customers in and around Houston. The request seeks to
establish uniform rates, charges and terms and conditions of service for the
cities and environs of the Houston service territory. As finally submitted to
the Railroad Commission and the cities, the proposed new rates would result in
an overall increase in annual revenue of $20.4 million, excluding carrying
costs on gas inventory of approximately $2 million. In January 2010, Gas
Operations withdrew its request for an annual cost of service adjustment
mechanism due to the uncertainty caused by the court’s ruling in the
above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission
issued its decision authorizing a revenue increase of $5.1 million annually,
reflecting reduced depreciation rates of $1.2 million. The hearing
examiner also recommended a surcharge of $0.9 million per year to recover
Hurricane Ike costs over three years.
In May
2009, CenterPoint Houston filed an application at the Texas Utility Commission
seeking approval of certain estimated 2010 energy efficiency program costs, an
energy efficiency performance bonus for 2008 programs and carrying costs,
totaling approximately $10 million. The application sought to begin
recovery of these costs through a surcharge effective July 1, 2010. In October
2009, the Texas Utility Commission issued its order approving recovery of the
2010 energy efficiency program costs and a partial performance bonus, plus
carrying costs, but refused to permit CenterPoint Houston to recover a
performance bonus of $2 million on approximately $10 million in 2008
energy efficiency costs expended pursuant to the terms of a settlement agreement
reached in CenterPoint Houston’s 2006 rate proceeding. CenterPoint
Houston has appealed the denial of the full 2008 performance bonus to the
district court in Travis County, Texas, where the case remains
pending.
Minnesota. In November 2006,
the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas
Operations for a waiver of MPUC rules in order to allow Gas Operations to
recover approximately $21 million in unrecovered purchased gas costs
related to periods prior to July 1, 2004. Those unrecovered gas costs were
identified as a result of revisions to previously approved calculations of
unrecovered purchased gas costs. Following that denial, Gas Operations recorded
a $21 million adjustment to reduce pre-tax earnings in the fourth quarter
of 2006 and reduced the regulatory asset related to these costs by an equal
amount. In March 2007, following the MPUC’s denial of reconsideration of its
ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of
the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been
arbitrary and capricious in denying Gas Operations a waiver. The MPUC sought
further review of the court of appeals decision from the Minnesota Supreme
Court. In July 2009, the Minnesota Supreme Court reversed the
decision of the Minnesota Court of Appeals and upheld the MPUC’s decision to
deny the requested variance. The court’s decision had no negative impact on
CenterPoint Energy’s or CERC’s financial condition, results of operations or
cash flows, as the costs at issue were written off at the time they were
disallowed.
In
November 2008, Gas Operations filed a request with the MPUC to increase its
rates for utility distribution service by $59.8 million annually. In
addition, Gas Operations sought an adjustment mechanism that would annually
adjust rates to reflect changes in use per customer. In December 2008, the
MPUC accepted the case and approved an interim rate increase of
$51.2 million, which became effective on January 2, 2009, subject to
refund. In January 2010, the MPUC issued its decision authorizing a revenue
increase of $41 million per year, with an overall rate of return of 8.09%
(10.24% return on equity).The difference between the rates approved by the MPUC
and amounts collected under the interim rates, $10 million as of December
31, 2009, is recorded in other current liabilities and will be refunded to
customers. The MPUC also authorized Gas Operations to implement a pilot program
for residential and small volume commercial customers that is intended to
decouple gas revenues from customers’ natural gas usage. In February 2010, CERC
filed a request for rehearing of the order by the MPUC. No
91
other
party to the case filed such a request. CERC and CenterPoint Energy
do not expect a final order to be issued in this proceeding until spring
2010.
Mississippi. In
July 2009, Gas Operations filed a request to increase its rates for utility
distribution service with the Mississippi Public Service Commission (MPSC). In
November 2009, as part of a settlement agreement in which the MPSC approved Gas
Operations’ retention of the compensation paid under the terms of an asset
management agreement, Gas Operations withdrew its rate request.
(d)
Regulatory Accounting
CenterPoint
Energy has a 50% ownership interest in Southeast Supply Header, LLC (SESH) which
owns and operates a 270-mile interstate natural gas pipeline. In
2009, SESH discontinued the use of guidance for accounting for regulated
operations, which resulted in CenterPoint Energy recording its share of the
effects of such write-offs of SESH’s regulatory assets through non-cash pre-tax
charges for the year ended December 31, 2009 of
$16 million. These non-cash charges are reflected in equity in
earnings of unconsolidated affiliates in the Statements of Consolidated
Income. The related tax benefits of $6 million are reflected in
the Income Tax Expense line in the Statements of Consolidated
Income.
(4) Derivative
Instruments
CenterPoint
Energy is exposed to various market risks. These risks arise from transactions
entered into in the normal course of business. CenterPoint Energy utilizes
derivative instruments such as physical forward contracts, swaps and options to
mitigate the impact of changes in commodity prices, weather and interest rates
on its operating results and cash flows.
(a)
Non-Trading Activities
Derivative Instruments.
CenterPoint Energy enters into certain derivative instruments to manage physical
commodity price risks and does not engage in proprietary or speculative
commodity trading. These financial instruments do not qualify or are
not designated as cash flow or fair value hedges.
During
the year ended December 31, 2007, CenterPoint Energy recorded increased
natural gas expense from unrealized net losses of
$10 million. During the year ended December 31, 2008,
CenterPoint Energy recorded increased natural gas revenues from unrealized net
gains of $101 million and increased natural gas expense from unrealized net
losses of $88 million, a net unrealized gain of
$13 million. During the year ended December 31, 2009,
CenterPoint Energy recorded decreased revenues from unrealized net losses of
$80 million and decreased natural gas expense from unrealized net gains of
$57 million, a net unrealized loss of $23 million.
In prior
years, CenterPoint Energy entered into certain derivative instruments that were
designated as cash flow hedges. The objective of these derivative instruments
was to hedge the price risk associated with natural gas purchases and sales to
reduce cash flow variability related to meeting CenterPoint Energy’s wholesale
and retail customer obligations. In 2007, CenterPoint Energy discontinued
designating these instruments as cash flow hedges. As of
December 31, 2009, there are no remaining amounts deferred in other
comprehensive income related to these instruments that had previously been
designated as cash flow hedges.
Weather Hedges. CenterPoint
Energy has weather normalization or other rate mechanisms that mitigate the
impact of weather on its gas operations in Arkansas, Louisiana, Oklahoma and a
portion of Texas. The remaining Gas Operations jurisdictions do not have such
mechanisms. As a result, fluctuations from normal weather may have a significant
positive or negative effect on the results of the gas operations in the
remaining jurisdictions and in CenterPoint Houston’s service
territory.
In 2007,
2008 and 2009, CenterPoint Energy entered into heating-degree day swaps to
mitigate the effect of fluctuations from normal weather on its financial
position and cash flows for the respective winter heating
seasons. The swaps were based on ten-year normal weather. During the
years ended December 31, 2007, 2008 and 2009, CenterPoint Energy recognized
losses of $-0-, $17 million and $7 million, respectively, related to
these swaps. The
92
losses
were substantially offset by increased revenues due to colder than normal
weather. Weather hedge losses are included in revenues in the Statements of
Consolidated Income.
Interest Rate
Swaps. During 2002, CenterPoint Energy settled
forward-starting interest rate swaps having an aggregate notional amount of
$1.5 billion at a cost of $156 million, which was recorded in other
comprehensive loss and was amortized into interest expense over the five-year
life of the designated fixed-rate debt. The settlement amount was
fully amortized at December 31, 2007. Amortization of amounts deferred in
accumulated other comprehensive loss for 2007 was $20 million.
Hedging of Future Debt
Issuances. In December 2007 and January 2008, CenterPoint
Energy entered into treasury rate lock derivative instruments (treasury rate
locks) having an aggregate notional amount of $300 million and a
weighted-average locked U.S. treasury rate on ten-year debt of 4.05%. These
treasury rate locks were executed to hedge the ten-year U.S. treasury rate
expected to be used in pricing $300 million of fixed-rate debt CenterPoint
Energy planned to issue in 2008, because changes in the U.S treasury rate would
cause variability in CenterPoint Energy’s forecasted interest payments. These
treasury rate lock derivatives were designated as cash flow hedges. Accordingly,
unrealized gains and losses associated with the treasury rate lock derivative
instruments were recorded as a component of accumulated other comprehensive
income. In May 2008, CenterPoint Energy settled its treasury rate locks for a
payment of $7 million. The $7 million loss recognized upon settlement
of the treasury rate locks was recorded as a component of accumulated other
comprehensive loss and will be recognized as a component of interest expense
over the ten-year life of the related $300 million senior notes issued in
May 2008. Amortization of amounts deferred in accumulated other comprehensive
loss for the years ended December 31, 2008 and 2009 was less than
$1 million. During the years ended December 31, 2007 and 2008,
CenterPoint Energy recognized a loss of $2 million and $5 million,
respectively, for these treasury rate locks in accumulated other comprehensive
loss. Ineffectiveness for the treasury rate locks was not material during the
years ended December 31, 2007 and 2008.
(b)
Derivative Fair Values and Income Statement Impacts
The
following tables present information about CenterPoint Energy’s derivative
instruments and hedging activities. The first table provides a balance sheet
overview of CenterPoint Energy’s Non-trading Derivative Assets and Liabilities
as of December 31, 2009, while the latter tables provide a breakdown of the
related income statement impact for the year ended December 31,
2009.
|
Fair
Value of Derivative Instruments
|
||||||||||
|
December 31,
2009
|
||||||||||
|
Total
derivatives not designated as hedging
instruments
|
Balance
Sheet
Location
|
Derivative
Assets
Fair
Value (2) (3)
|
Derivative
Liabilities
Fair
Value (2) (3)
|
|||||||
|
(in
millions)
|
||||||||||
|
Commodity
contracts (1)
|
Current
Assets
|
$ | 46 | $ | (7 | ) | ||||
|
Commodity
contracts (1)
|
Other
Assets
|
16 | (1 | ) | ||||||
|
Commodity
contracts (1)
|
Current
Liabilities
|
20 | (123 | ) | ||||||
|
Commodity
contracts (1)
|
Other
Liabilities
|
1 | (86 | ) | ||||||
|
Indexed
debt securities derivative
|
Current
Liabilities
|
- | (201 | ) | ||||||
|
Total
|
$ | 83 | $ | (418 | ) | |||||
_________
|
|
(1)
|
Commodity
contracts are subject to master netting arrangements and are presented on
a net basis in the Consolidated Balance Sheets. This netting can cause
derivative assets to be ultimately presented in a (liability) account on
the Consolidated Balance Sheets. Likewise, derivative
(liabilities) could be presented in an asset
account.
|
|
|
(2)
|
The
fair value shown for commodity contracts is comprised of derivative gross
volumes totaling 674 billion cubic feet (Bcf) or a net 152 Bcf long
position. Of the net long position, basis swaps constitute 71
Bcf and volumes associated with price stabilization activities of the
Natural Gas Distribution business segment comprise 51
Bcf.
|
|
|
(3)
|
The
net of total non-trading derivative assets and liabilities is a
$39 million liability as shown on CenterPoint Energy’s Consolidated
Balance Sheets, and is comprised of the commodity contracts derivative
assets and liabilities separately shown above offset by collateral netting
of $95 million.
|
For
CenterPoint Energy’s price stabilization activities of the Natural Gas
Distribution business segment, the settled costs of derivatives are ultimately
recovered through purchased gas adjustments. Accordingly, the net unrealized
gains and losses associated with interim price movements on contracts that are
accounted for as derivatives and probable of recovery through purchased gas
adjustments are recorded as net regulatory assets. For those derivatives that
are not included in purchased gas adjustments, unrealized gains and losses and
settled amounts are recognized in the Statements of Consolidated Income as
revenue for retail sales derivative contracts and as natural gas expense for
natural gas derivatives and non-retail related physical gas derivatives.
Unrealized gains and losses on indexed debt securities are recorded as Other
Income (Expense) on the Statements of Consolidated Income.
|
Income
Statement Impact of Derivative Activity
|
||||||
|
Total
derivatives not designated as hedging
instruments
|
Income
Statement Location
|
Year
Ended
December 31,
2009
|
||||
|
(in
millions)
|
||||||
|
Commodity
contracts
|
Gains
(Losses) in Revenue
|
$ | 102 | |||
|
Commodity
contracts (1)
|
Gains
(Losses) in Expense: Natural Gas
|
(255 | ) | |||
|
Indexed
debt securities derivative
|
Gains
(Losses) in Other Income (Expense)
|
(68 | ) | |||
|
Total
|
$ | (221 | ) | |||
_________
|
|
(1)
|
The
Gains (Losses) in Expense: Natural Gas includes $(181) million of
costs associated with price stabilization activities of the Natural Gas
Distribution business segment that will be ultimately recovered through
purchased gas adjustments.
|
(c)
Credit Risk Contingent Features
CenterPoint
Energy enters into financial derivative contracts containing material adverse
change provisions. These provisions require CenterPoint Energy to
post additional collateral if the Standard & Poor’s Rating Services or
Moody’s Investors Service, Inc. credit rating of CenterPoint Energy is
downgraded. The total fair value of the derivative instruments that
contain credit risk contingent features that are in a net liability position at
December 31, 2009 is $140 million. The aggregate fair value
of assets that are already posted as collateral at December 31, 2009 is
$65 million. If all derivative contracts (in a net liability
position) containing credit risk contingent features were triggered at
December 31, 2009, a maximum of $75 million of additional assets would
be required to be posted as collateral.
(d)
Credit Quality of Counterparties
In
addition to the risk associated with price movements, credit risk is also
inherent in CenterPoint Energy’s non-trading derivative activities. Credit risk
relates to the risk of loss resulting from non-performance of contractual
obligations by a counterparty. The following table shows the composition of
counterparties to the non-trading derivative assets of CenterPoint Energy as of
December 31, 2008 and 2009 (in millions):
|
December 31,
2008
|
December 31,
2009
|
|||||||||||||||
|
Investment
Grade(1)
|
Total
|
Investment
Grade(1)
|
Total
|
|||||||||||||
|
Energy
marketers
|
$ | 8 | $ | 9 | $ | 6 | $ | 6 | ||||||||
|
Financial
institutions
|
4 | 4 | 2 | 4 | ||||||||||||
|
Retail
end users (2)
|
5 | 125 | 1 | 44 | ||||||||||||
|
Total
|
$ | 17 | $ | 138 | $ | 9 | $ | 54 | ||||||||
|
|
(1)
|
"Investment
grade" is primarily determined using publicly available credit ratings
along with the consideration of credit support (such as parent company
guaranties) and collateral, which encompass cash and standby letters of
credit. For unrated counterparties, CenterPoint Energy performs financial
statement analysis, considering contractual rights and restrictions and
collateral, to create a synthetic credit
rating.
|
|
|
(2)
|
Retail
end users represent commercial and industrial customers who have
contracted to fix the price of a portion of their physical gas
requirements for future periods.
|
(5) Fair
Value Measurements
Effective
January 1, 2008, CenterPoint Energy adopted new accounting guidance on fair
value measurements which requires additional disclosures about CenterPoint
Energy’s financial assets and liabilities that are measured at fair
value. Effective January 1, 2009, CenterPoint Energy adopted this new
guidance for nonfinancial assets and liabilities, which adoption had no impact
on CenterPoint Energy’s financial position, results of operations or cash
flows. Beginning in January 2008, assets and liabilities recorded at
fair value in the Consolidated Balance Sheets are categorized based upon the
level of judgment associated with the inputs used to measure their value.
Hierarchical levels, as defined in this guidance and directly related to the
amount of subjectivity associated with the inputs to fair valuations of these
assets and liabilities, are as follows:
Level 1:
Inputs are unadjusted quoted prices in active markets for identical assets or
liabilities at the measurement date. The types of assets carried at Level 1
fair value generally are financial derivatives, investments and equity
securities listed in active markets.
Level 2:
Inputs, other than quoted prices included in Level 1, are observable for the
asset or liability, either directly or indirectly. Level 2 inputs include quoted
prices for similar instruments in active markets, and inputs other than quoted
prices that are observable for the asset or liability. Fair value assets
and liabilities that are generally included in this category are derivatives
with fair values based on inputs from actively quoted markets.
Level 3:
Inputs are unobservable for the asset or liability, and include situations where
there is little, if any, market activity for the asset or liability. In certain
cases, the inputs used to measure fair value may fall into different levels of
the fair value hierarchy. In such cases, the level in the fair value hierarchy
within which the fair value measurement in its entirety falls has been
determined based on the lowest level input that is significant to the fair value
measurement in its entirety. Unobservable inputs reflect CenterPoint Energy’s
judgments about the assumptions market participants would use in pricing the
asset or liability since limited market data exists. CenterPoint Energy develops
these inputs based on the best information available, including CenterPoint
Energy’s own data. CenterPoint Energy’s Level 3 derivative
instruments primarily consist of options that are not traded on recognized
exchanges and are valued using option pricing models.
The
following tables present information about CenterPoint Energy’s assets and
liabilities (including derivatives that are presented net) measured at fair
value on a recurring basis as of December 31, 2008 and 2009, and indicate
the fair value hierarchy of the valuation techniques utilized by CenterPoint
Energy to determine such fair value.
|
Quoted
Prices in
Active
Markets
for Identical
Assets
(Level
1)
|
Significant
Other
Observable
Inputs
(Level
2)
|
Significant
Unobservable
Inputs
(Level
3)
|
Netting
Adjustments
(1)
|
Balance
as
of
December 31,
2008
|
||||||||||||||||
|
(in
millions)
|
||||||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Corporate
equities
|
$ | 218 | $ | - | $ | - | $ | - | $ | 218 | ||||||||||
|
Investments,
including money
market
funds
|
70 | - | - | - | 70 | |||||||||||||||
|
Derivative
assets
|
8 | 155 | 49 | (74 | ) | 138 | ||||||||||||||
|
Total
assets
|
$ | 296 | $ | 155 | $ | 49 | $ | (74 | ) | $ | 426 | |||||||||
|
Liabilities
|
||||||||||||||||||||
|
Indexed
debt securities
derivative
|
$ | - | $ | 133 | $ | - | $ | - | $ | 133 | ||||||||||
|
Derivative
liabilities
|
44 | 244 | 107 | (261 | ) | 134 | ||||||||||||||
|
Total
liabilities
|
$ | 44 | $ | 377 | $ | 107 | $ | (261 | ) | $ | 267 | |||||||||
__________
|
|
(1)
|
Amounts
represent the impact of legally enforceable master netting agreements that
allow CenterPoint Energy to settle positive and negative positions and
also include cash collateral of $187 million posted with the same
counterparties.
|
|
Quoted
Prices in
Active
Markets
for Identical
Assets
(Level
1)
|
Significant
Other
Observable
Inputs
(Level
2)
|
Significant
Unobservable
Inputs
(Level
3)
|
Netting
Adjustments
(1)
|
Balance
as
of
December 31,
2009
|
||||||||||||||||
|
(in
millions)
|
||||||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Corporate
equities
|
$ | 301 | $ | - | $ | - | $ | - | $ | 301 | ||||||||||
|
Investments,
including money
market
funds
|
41 | - | - | - | 41 | |||||||||||||||
|
Derivative
assets
|
1 | 77 | 5 | (29 | ) | 54 | ||||||||||||||
|
Total
assets
|
$ | 343 | $ | 77 | $ | 5 | $ | (29 | ) | $ | 396 | |||||||||
|
Liabilities
|
||||||||||||||||||||
|
Indexed
debt securities
derivative
|
$ | - | $ | 201 | $ | - | $ | - | $ | 201 | ||||||||||
|
Derivative
liabilities
|
12 | 194 | 11 | (124 | ) | 93 | ||||||||||||||
|
Total
liabilities
|
$ | 12 | $ | 395 | $ | 11 | $ | (124 | ) | $ | 294 | |||||||||
__________
|
|
(1)
|
Amounts
represent the impact of legally enforceable master netting agreements that
allow CenterPoint Energy to settle positive and negative positions and
also include cash collateral of $95 million posted with the same
counterparties.
|
The
following tables present additional information about assets or liabilities,
including derivatives that are measured at fair value on a recurring basis for
which CenterPoint Energy has utilized Level 3 inputs to determine fair
value:
|
Fair
Value Measurements Using Significant
Unobservable
Inputs (Level 3)
|
||||||||
|
Derivative
assets and liabilities, net
|
||||||||
|
Year
Ended December 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
(in
millions)
|
||||||||
|
Beginning
balance
|
$ | (3 | ) | $ | (58 | ) | ||
|
Total
unrealized gains or (losses):
|
||||||||
|
Included
in earnings
|
(11 | ) | (1 | ) | ||||
|
Included
in regulatory assets
|
(10 | ) | (16 | ) | ||||
|
Purchases,
sales, other settlements, net
|
(35 | ) | 69 | (1) | ||||
|
Net
transfers into Level 3
|
1 | - | ||||||
|
Ending
balance
|
$ | (58 | ) | $ | (6 | ) | ||
|
The
amount of total gains for the period included in earnings
attributable
to the change in unrealized gains or losses relating to
assets
still held at the reporting date
|
$ | 7 | $ | 1 | ||||
|
|
(1)
|
Purchases,
sales, other settlements, net include a $41 million loss and a
$66 million gain in 2008 and 2009, respectively, associated with
price stabilization activities of CenterPoint Energy’s Natural Gas
Distribution business segment.
|
(6) Indexed
Debt Securities (ZENS) and Time Warner Securities
(a)
Investment in Time Warner Securities
In 1995,
CenterPoint Energy sold a cable television subsidiary to TW and received TW
convertible preferred stock (TW Preferred) as partial consideration. In July
1999, CenterPoint Energy converted its 11 million shares of TW Preferred
into 45.8 million shares of TW common stock (TW Common). In March 2009, TW
spun off its ownership of Time Warner Cable Inc. (TWC) by distributing 0.08367
shares of TWC common stock (TWC Common) for every share of TW Common
held. Subsequently, in March 2009 TW declared a 1-for-3 reverse stock
split. In December 2009, TW spun off its ownership in AOL Inc. (AOL)
by distributing one share of AOL common
96
stock
(AOL Common) for every 11 shares of TW Common held. A subsidiary of
CenterPoint Energy now holds 7.2 million shares of TW Common,
1.8 million shares of TWC Common and 0.7 million shares of AOL Common
(together with the TW Common and TWC Common, the TW Securities) which are
classified as trading securities and are expected to be held to facilitate
CenterPoint Energy’s ability to meet its obligation under the 2.0% Zero-Premium
Exchangeable Subordinated Notes due 2029 (ZENS). Unrealized gains and losses
resulting from changes in the market value of the TW Securities are recorded in
CenterPoint Energy’s Statements of Consolidated Income.
(b)
ZENS
In
September 1999, we issued ZENS having an original principal amount of
$1.0 billion of which $840 million remain outstanding at
December 31, 2009. Each ZENS note was originally exchangeable at the
holder’s option at any time for an amount of cash equal to 95% of the market
value of the reference shares of TW Common attributable to such note. The number
and identity of the reference shares attributable to each ZENS note are adjusted
for certain corporate events. As of December 31, 2009, the reference shares
for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of TWC
Common and 0.045455 share of AOL Common, which reflects adjustments resulting
from the March 2009 distribution by TW of shares of TWC Common, TW’s March 2009
reverse stock split and the December 2009 distribution by TW of shares of AOL
Common. CenterPoint Energy pays interest on the ZENS at an annual rate of
2% plus the amount of any quarterly cash dividends paid in respect of the
reference shares attributable to the ZENS. The principal amount of ZENS is
subject to being increased or decreased to the extent that the annual yield from
interest and cash dividends on the reference shares is less than or more than
2.309%. This is defined in the ZENS instrument as "contingent principal." At
December 31, 2009, ZENS having an original principal amount of
$840 million and a contingent principal amount of $814 million were
outstanding and were exchangeable, at the option of the holders, for cash equal
to 95% of the market value of reference shares deemed to be attributable to the
ZENS. At December 31, 2009, the market value of such shares was
approximately $300 million, which would provide an exchange amount of $340
for each $1,000 original principal amount of ZENS. At maturity of the ZENS in
2029, CenterPoint Energy will be obligated to pay in cash the higher of the
contingent principal amount of the ZENS or an amount based on the then-current
market value of the reference shares, which will include any additional
publicly-traded securities distributed with respect to the current reference
shares prior to maturity.
The ZENS
obligation is bifurcated into a debt component and a derivative component (the
holder’s option to receive the appreciated value of the reference shares at
maturity). The bifurcated debt component accretes through interest charges at
17.4% annually up to the contingent principal amount of the ZENS in 2029. Such
accretion will be reduced by annual cash interest payments, as described above.
The derivative component is recorded at fair value and changes in the fair value
of the derivative component are recorded in CenterPoint Energy’s Statements of
Consolidated Income. During 2007, 2008 and 2009, CenterPoint Energy recorded a
gain (loss) of $(114) million, $(139) million and $82 million,
respectively, on CenterPoint Energy’s investment in TW Securities. During 2007,
2008 and 2009, CenterPoint Energy recorded a gain (loss) of $111 million,
$128 million and $(68) million, respectively, associated with the fair
value of the derivative component of the ZENS obligation. Changes in the fair
value of the TW Securities held by CenterPoint Energy are expected to
substantially offset changes in the fair value of the derivative component of
the ZENS.
The
following table sets forth summarized financial information regarding
CenterPoint Energy’s investment in TW Securities and each component of
CenterPoint Energy’s ZENS obligation (in millions).
|
TW
Securities
|
Debt
Component
of
ZENS
|
Derivative
Component
of
ZENS
|
||||||||||
|
Balance
at December 31, 2006
|
$ | 471 | $ | 111 | $ | 372 | ||||||
|
Accretion
of debt component of ZENS
|
- | 20 | - | |||||||||
|
2%
interest paid
|
- | (17 | ) | - | ||||||||
|
Gain
on indexed debt securities
|
- | - | (111 | ) | ||||||||
|
Loss
on TW Common
|
(114 | ) | - | - | ||||||||
|
Balance
at December 31, 2007
|
357 | 114 | 261 | |||||||||
|
Accretion
of debt component of ZENS
|
- | 20 | - | |||||||||
|
2%
interest paid
|
- | (17 | ) | - | ||||||||
|
Gain
on indexed debt securities
|
- | - | (128 | ) | ||||||||
|
Loss
on TW Common
|
(139 | ) | - | - | ||||||||
|
Balance
at December 31, 2008
|
218 | 117 | 133 | |||||||||
|
Accretion
of debt component of ZENS
|
- | 21 | - | |||||||||
|
2%
interest paid
|
- | (17 | ) | - | ||||||||
|
Loss
on indexed debt securities
|
- | - | 68 | |||||||||
|
Gain
on TW Securities
|
82 | - | - | |||||||||
|
Balance
at December 31, 2009
|
$ | 300 | $ | 121 | $ | 201 | ||||||
(7) Equity
(a)
Capital Stock
CenterPoint
Energy has 1,020,000,000 authorized shares of capital stock, comprised of
1,000,000,000 shares of $0.01 par value common stock and
20,000,000 shares of $0.01 par value cumulative preferred
stock.
During
the year ended December 31, 2009, CenterPoint Energy received net proceeds
of approximately $280 million from the issuance of 24.2 million common
shares in an underwritten public offering, net proceeds of $148 million
from the issuance of 14.3 million common shares through a continuous
offering program, proceeds of approximately $57 million from the sale of
approximately 4.9 million common shares to CenterPoint Energy’s defined
contribution plan and proceeds of approximately $15 million from the sale
of approximately 1.3 million common shares to participants in CenterPoint
Energy’s enhanced dividend reinvestment plan.
(b)
Shareholder Rights Plan
CenterPoint
Energy has a Shareholder Rights Plan that states that each share of its common
stock includes one associated preference stock purchase right (Right) which
entitles the registered holder to purchase from CenterPoint Energy a unit
consisting of one-thousandth of a share of Series A Preference Stock. The
Rights, which expire on December 11, 2011, are exercisable upon some events
involving the acquisition of 20% or more of CenterPoint Energy’s outstanding
common stock. Upon the occurrence of such an event, each Right entitles the
holder to receive common stock with a current market price equal to two times
the exercise price of the Right. At any time prior to becoming exercisable,
CenterPoint Energy may repurchase the Rights at a price of $0.005 per
Right. There are 700,000 shares of Series A Preference Stock reserved
for issuance upon exercise of the Rights.
(8) Short-term
Borrowings and Long-term Debt
|
December 31,
2008
|
December 31,
2009
|
|||||||||||||||
|
Long-Term
|
Current(1)
|
Long-Term
|
Current(1)
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Short-term
borrowings:
|
||||||||||||||||
|
CERC
Corp. receivables facility
|
$ | - | $ | 78 | $ | - | $ | - | ||||||||
|
Inventory
financing
|
- | 75 | - | 55 | ||||||||||||
|
Total
short-term borrowings
|
- | 153 | - | 55 | ||||||||||||
|
Long-term
debt:
|
||||||||||||||||
|
CenterPoint
Energy:
|
||||||||||||||||
|
ZENS(2)
|
- | 117 | - | 121 | ||||||||||||
|
Senior
notes 5.95% to 7.25% due 2010 to 2018
|
950 | - | 750 | 200 | ||||||||||||
|
Pollution
control bonds 4.00% due 2015(3)
|
151 | - | 151 | - | ||||||||||||
|
Pollution
control bonds 4.70% to 8.00% due 2011 to 2030(4)(5)
|
871 | - | 581 | 290 | ||||||||||||
|
Bank
loans due 2012(6)
|
264 | - | - | - | ||||||||||||
|
Other
|
12 | 1 | - | 7 | ||||||||||||
|
CenterPoint
Houston:
|
||||||||||||||||
|
First
mortgage bonds 9.15% due 2021
|
102 | - | 102 | - | ||||||||||||
|
General
mortgage bonds 5.60% to 7.00% due 2013 to 2033
|
1,262 | - | 1,762 | - | ||||||||||||
|
Pollution
control bonds 3.625% to 5.60% due 2012 to 2027(7)
|
229 | - | 229 | - | ||||||||||||
|
System
restoration bonds 1.833% to 4.243% due 2010 to 2022
|
- | - | 645 | 20 | ||||||||||||
|
Transition
Bonds 4.192% to 5.63% due 2010 to 2020
|
2,381 | 208 | 2,160 | 221 | ||||||||||||
|
Bank
loans due 2012(6)
|
251 | - | - | - | ||||||||||||
|
CERC
Corp.:
|
||||||||||||||||
|
Convertible
subordinated debentures 6.00% due 2012 (8)
|
44 | 7 | - | 44 | ||||||||||||
|
Senior
notes 5.95% to 7.875% due 2011 to 2037
|
2,747 | - | 2,747 | - | ||||||||||||
|
Bank
loans due 2012(6)
|
926 | - | - | - | ||||||||||||
|
Other
|
1 | - | 1 | - | ||||||||||||
|
Unamortized
discount and premium(9)
|
(10 | ) | - | (9 | ) | - | ||||||||||
|
Total
long-term debt
|
10,181 | 333 | 9,119 | 903 | ||||||||||||
|
Total
debt
|
$ | 10,181 | $ | 486 | $ | 9,119 | $ | 958 | ||||||||
__________
|
|
(1)
|
Includes
amounts due or exchangeable within one year of the date
noted.
|
|
|
(2)
|
CenterPoint
Energy’s ZENS obligation is bifurcated into a debt component and an
embedded derivative component. For additional information regarding ZENS,
see Note 6(b). As ZENS are exchangeable for cash at any time at the option
of the holders, these notes are classified as a current portion of
long-term debt.
|
|
|
(3)
|
These
series of debt are secured by first mortgage bonds of CenterPoint
Houston.
|
|
|
(4)
|
$527 million
of these series of debt is secured by general mortgage bonds of
CenterPoint Houston.
|
|
|
(5)
|
In
January 2010, CenterPoint Energy purchased $290 million principal
amount of pollution control bonds issued on its behalf at 101% of their
principal amount.
|
|
|
(6)
|
Classified
as long-term debt because the termination dates of the facilities under
which the funds were borrowed are more than one year from the date
noted.
|
|
|
(7)
|
These
series of debt are secured by general mortgage bonds of CenterPoint
Houston.
|
|
|
(8)
|
In
January 2010, pursuant to a notice of redemption dated December 11, 2009,
CERC redeemed all of its outstanding 6% convertible subordinated
debentures due in 2012.
|
|
|
(9)
|
Debt
acquired in business acquisitions is adjusted to fair market value as of
the acquisition date. Included in long-term debt is additional unamortized
premium related to fair value adjustments of long-term debt of $3
million
|
|
|
|
and
$2 million at December 31, 2008 and 2009, respectively, which is
being amortized over the respective remaining term of the related
long-term debt.
|
(a)
Short-term Borrowings
Receivables
Facility. On October 9, 2009, CERC amended its receivables
facility to extend the termination date to October 8,
2010. Availability under CERC’s 364-day receivables facility now
ranges from $150 million to $375 million, reflecting seasonal changes
in receivables balances. As of December 31, 2008 and 2009, the
facility size was $128 million and $150 million, respectively. As of
December 31, 2008 and 2009, advances under the receivables facilities were
$78 million and $-0-, respectively.
Inventory Financing. In
December 2008, Gas Operations entered into an asset management agreement whereby
it sold $110 million of its natural gas in storage and agreed to repurchase
an equivalent amount of natural gas during the 2008-2009 winter heating season
for payments totaling $114 million. This transaction was
accounted for as a financing and was paid in full during 2009.
In
October 2009, Gas Operations entered into asset management agreements associated
with its utility distribution service in Arkansas, Louisiana and Oklahoma.
Pursuant to the provisions of the agreements, Gas Operations sold
$104 million of its natural gas in storage and agreed to repurchase an
equivalent amount of natural gas during the 2009-2010 winter heating season at
the same cost, plus a financing charge. This transaction was accounted for as a
financing and, as of December 31, 2009, a principal obligation of
$55 million remained.
Also in
October 2009, Gas Operations entered into asset management agreements associated
with its utility distribution service in Louisiana, Mississippi and Texas. In
connection with these asset management agreements, Gas Operations exchanged
natural gas in storage for the right to receive an equivalent amount of natural
gas during the 2009-2010 winter heating season. Although title to the natural
gas in storage was transferred to the third party, the natural gas continues to
be accounted for as inventory due to the right to receive an equivalent amount
of natural gas during the current winter heating season. As of December 31,
2009, CenterPoint Energy’s Consolidated Balance Sheets reflect $10 million
in Inventory related to these agreements.
Revolving Credit Facility. On
October 6, 2009, CenterPoint Houston terminated its $600 million 364-day
credit facility which was secured by a pledge of $600 million of general
mortgage bonds issued by CenterPoint Houston.
(b)
Long-term Debt
General Mortgage Bonds. In
January 2009, CenterPoint Houston issued $500 million aggregate principal
amount of general mortgage bonds due in March 2014 with an interest rate of
7.00%. The proceeds from the sale of the bonds were used for general
corporate purposes, including the repayment of outstanding borrowings under
CenterPoint Houston’s revolving credit facility and the money pool, capital
expenditures and storm restoration costs associated with Hurricane
Ike.
System Restoration Bonds. In
July 2009, CenterPoint Houston filed with the Texas Utility Commission its
application for a financing order to recover the portion of approved costs
related to distribution service through the issuance of system restoration
bonds. In August 2009, the Texas Utility Commission issued a financing order
allowing CenterPoint Houston to securitize $643 million in distribution
service costs plus carrying charges from September 1, 2009 through the date
the system restoration bonds were issued, as well as certain up-front qualified
costs capped at approximately $6 million. In November 2009,
CenterPoint Houston issued approximately $665 million of system restoration
bonds through its CenterPoint Energy Restoration Bond Company, LLC subsidiary
with interest rates of 1.833% to 4.243% and final maturity dates ranging from
February 2016 to August 2023. The bonds will be repaid over time
through a charge imposed on customers.
Revolving Credit Facilities.
As of December 31, 2008 and 2009, the following loan balances were
outstanding under CenterPoint Energy’s long-term revolving credit facilities (in
millions):
|
December 31,
2008
|
December 31,
2009
|
|||||||
|
CenterPoint
Energy credit facility borrowings
|
$ | 264 | $ | - | ||||
|
CenterPoint
Houston credit facility borrowings
|
251 | - | ||||||
|
CERC
Corp. credit facility borrowings
|
926 | - | ||||||
|
Total
credit facility borrowings
|
$ | 1,441 | $ | - | ||||
In
addition, as of December 31, 2008 and 2009, CenterPoint Energy had
approximately $27 million and $25 million, respectively, of
outstanding letters of credit under its $1.2 billion credit facility.
CenterPoint Houston had approximately $4 million of outstanding letters of
credit under its $289 million credit facility as of both December 31, 2008
and 2009. There was no commercial paper outstanding that would have been
backstopped by CenterPoint Energy’s $1.2 billion credit facility or by CERC
Corp.’s credit facility as of December 31, 2008 and
2009. CenterPoint Energy, CenterPoint Houston and CERC Corp. were in
compliance with all debt covenants as of December 31, 2009.
CenterPoint
Energy’s $1.2 billion credit facility has a first drawn cost of the London
Interbank Offered Rate (LIBOR) plus 55 basis points based on CenterPoint
Energy’s current credit ratings. The facility contains a debt (excluding
transition and system restoration bonds) to earnings before interest, taxes,
depreciation and amortization (EBITDA) covenant (as those terms are defined in
the facility). Such covenant was modified twice in 2008 to provide additional
debt capacity. The second modification was to provide debt capacity
pending the financing of system restoration costs following Hurricane
Ike. That modification was terminated with CenterPoint Houston’s
issuance of bonds to securitize such costs in November 2009. In
February 2010, CenterPoint Energy amended its credit facility to modify the
financial ratio covenant to allow for a temporary increase of the permitted
ratio of debt (excluding transition and system restoration bonds) to EBITDA from
5 times to 5.5 times if CenterPoint Houston experiences damage from a natural
disaster in its service territory and CenterPoint Energy certifies to the
administrative agent that CenterPoint Houston has incurred system restoration
costs reasonably likely to exceed $100 million in a calendar year, all or
part of which CenterPoint Houston intends to seek to recover through
securitization financing. Such temporary increase in the financial ratio
covenant would be in effect from the date CenterPoint Energy delivers its
certification until the earliest to occur of (i) the completion of the
securitization financing, (ii) the first anniversary of CenterPoint Energy’s
certification or (iii) the revocation of such certification.
CenterPoint
Houston’s $289 million credit facility contains a debt (excluding
transition and system restoration bonds) to total capitalization covenant. The
facility’s first drawn cost is LIBOR plus 45 basis points based on CenterPoint
Houston’s current credit ratings.
On
October 7, 2009, the size of the CERC Corp. revolving credit facility was
reduced from $950 million to $915 million through removal of Lehman
Brothers Bank, FSB (Lehman) as a lender. Prior to its removal, Lehman
had a $35 million commitment to lend. All credit facility loans
to CERC Corp. that were funded by Lehman were repaid in September
2009. CERC Corp.’s $915 million credit facility’s first drawn
cost is LIBOR plus 45 basis points based on CERC Corp.’s current credit ratings.
The facility contains a debt to total capitalization covenant.
Under
CenterPoint Energy’s $1.2 billion credit facility, CenterPoint Houston’s
$289 million credit facility and CERC Corp.’s $915 million credit
facility, an additional utilization fee of 5 basis points applies to borrowings
any time more than 50% of the facility is utilized. The spread to LIBOR and the
utilization fee fluctuate based on the borrower’s credit rating.
Maturities. CenterPoint
Energy’s maturities of long-term debt, capital leases and sinking fund
requirements, excluding the ZENS obligation, are $782 million in 2010,
$852 million in 2011, $353 million in 2012, $1.5 billion in 2013
and $1.2 billion in 2014. Maturities include transition and
system restoration bond principal repayments on scheduled payment dates
aggregating $241 million in 2010, $283 million in 2011,
$307 million in 2012, $330 million in 2013 and $235 million in
2014. Maturities in 2010 include $290 million of pollution
control bonds issued on behalf of CenterPoint Energy which were purchased by
CenterPoint Energy in January 2010 and $45 million of debentures redeemed
in January 2010.
Liens. As of
December 31, 2009, CenterPoint Houston’s assets were subject to liens
securing approximately $253 million of first mortgage bonds. Sinking or
improvement fund and replacement fund requirements on the first mortgage bonds
may be satisfied by certification of property additions. Sinking fund and
replacement fund requirements for 2007, 2008 and 2009 have been satisfied by
certification of property additions. The replacement fund requirement to be
satisfied in 2010 is approximately $172 million, and the sinking fund
requirement to be satisfied in 2010 is approximately $3 million.
CenterPoint Energy expects CenterPoint Houston to meet these 2010 obligations by
certification of property additions. As of December 31, 2009, CenterPoint
Houston’s assets were also subject to liens securing approximately
$2.5 billion of general mortgage bonds which are junior to the liens of the
first mortgage bonds.
(9) Income
Taxes
The
components of CenterPoint Energy’s income tax expense were as
follows:
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Current
income tax expense (benefit):
|
||||||||||||
|
Federal
|
$ | 161 | $ | (221 | ) | $ | (103 | ) | ||||
|
State
|
32 | 11 | 10 | |||||||||
|
Total
current expense (benefit)
|
193 | (210 | ) | (93 | ) | |||||||
|
Deferred
income tax expense (benefit):
|
||||||||||||
|
Federal
|
47 | 437 | 251 | |||||||||
|
State
|
(47 | ) | 50 | 18 | ||||||||
|
Total
deferred expense
|
- | 487 | 269 | |||||||||
|
Total
income tax expense
|
$ | 193 | $ | 277 | $ | 176 | ||||||
A
reconciliation of the expected federal income tax expense using the federal
statutory income tax rate to the actual income tax expense and resulting
effective income tax rate is as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Income
before income taxes
|
$ | 588 | $ | 723 | $ | 548 | ||||||
|
Federal
statutory income tax rate
|
35 | % | 35 | % | 35 | % | ||||||
|
Expected
federal income tax expense
|
206 | 253 | 192 | |||||||||
|
Increase
(decrease) in tax expense resulting from:
|
||||||||||||
|
State
income tax expense (benefit), net of federal income tax
|
(10 | ) | 40 | 18 | ||||||||
|
Amortization
of investment tax credit
|
(8 | ) | (7 | ) | (7 | ) | ||||||
|
Tax
basis balance sheet adjustments
|
25 | - | - | |||||||||
|
Increase
(decrease) in settled and uncertain income tax positions
|
(20 | ) | 8 | (5 | ) | |||||||
|
Other,
net
|
- | (17 | ) | (22 | ) | |||||||
|
Total
|
(13 | ) | 24 | (16 | ) | |||||||
|
Total
income tax expense
|
$ | 193 | $ | 277 | $ | 176 | ||||||
|
Effective
tax rate
|
32.8 | % | 38.4 | % | 32.1 | % | ||||||
As a
result of its settlement with the IRS for tax years 2004 and 2005, CenterPoint
Energy recorded an income tax benefit of approximately $11 million in 2009
related to a reduction in the liability for uncertain tax positions of
approximately $41 million. The state income tax expense of $18 million
for 2009 includes a benefit of approximately $12 million, net of federal
income tax effect, related to adjustments in prior years’ state
estimates. Changes in the Texas State Franchise Tax Law (Texas margin
tax) resulted in classifying Texas margin tax of approximately $8 million
and $10 million, net of federal income tax effect, as income tax expense in
2008 and 2009, respectively, for CenterPoint Houston. The state
income tax benefit of $10 million for 2007 includes a benefit of
approximately $30 million, net of federal income tax effect, as a result of
the Texas margin tax and a Texas state tax examination for the tax years 2002
and 2004.
The tax
effects of temporary differences that give rise to significant portions of
deferred tax assets and liabilities were as follows:
|
December 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
(In
millions)
|
||||||||
|
Deferred
tax assets:
|
||||||||
|
Current:
|
||||||||
|
Allowance
for doubtful accounts
|
$ | 15 | $ | 10 | ||||
|
Deferred
gas costs
|
13 | 7 | ||||||
|
Other
|
1 | - | ||||||
|
Total
current deferred tax assets
|
29 | 17 | ||||||
|
Non-current:
|
||||||||
|
Loss
and credit carryforwards
|
36 | 42 | ||||||
|
Employee
benefits
|
360 | 366 | ||||||
|
Other
|
57 | 51 | ||||||
|
Total
non-current deferred tax assets before valuation allowance
|
453 | 459 | ||||||
|
Valuation
allowance
|
(5 | ) | (5 | ) | ||||
|
Total
non-current deferred tax assets, net of valuation allowance
|
448 | 454 | ||||||
|
Total
deferred tax assets, net of valuation allowance
|
477 | 471 | ||||||
|
Deferred
tax liabilities:
|
||||||||
|
Current:
|
||||||||
|
Unrealized
gain on indexed debt securities
|
$ | 373 | $ | 366 | ||||
|
Unrealized
gain on TW securities
|
28 | 57 | ||||||
|
Total
current deferred tax liabilities
|
401 | 423 | ||||||
|
Non-current:
|
||||||||
|
Depreciation
|
1,679 | 1,887 | ||||||
|
Regulatory
assets, net
|
1,319 | 1,298 | ||||||
|
Other
|
58 | 45 | ||||||
|
Total
non-current deferred tax liabilities
|
3,056 | 3,230 | ||||||
|
Total
deferred tax liabilities
|
3,457 | 3,653 | ||||||
|
Accumulated
deferred income taxes, net
|
$ | 2,980 | $ | 3,182 | ||||
Tax Attribute Carryforwards and
Valuation Allowance. At December 31, 2009, CenterPoint
Energy has approximately $213 million of state net operating loss
carryforwards which expire in various years between 2010 and 2029. A valuation
allowance has been established for approximately $49 million of the state
net operating loss carryforwards that may not be realized. CenterPoint Energy
has approximately $244 million of state capital loss carryforwards which
expire in 2017 for which a valuation allowance has been
established.
Uncertain Income Tax
Positions. The following table reconciles the beginning and ending
balance of CenterPoint Energy’s unrecognized tax benefits:
|
December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Balance,
beginning of year
|
$ | 72 | $ | 82 | $ | 117 | ||||||
|
Tax
Positions related to prior years:
|
||||||||||||
|
Additions
|
28 | 20 | 56 | |||||||||
|
Reductions
|
(20 | ) | (2 | ) | (25 | ) | ||||||
|
Tax
Positions related to current year:
|
||||||||||||
|
Additions
|
4 | 17 | 56 | |||||||||
|
Settlements
|
(2 | ) | — | (17 | ) | |||||||
|
Balance,
end of year
|
$ | 82 | $ | 117 | $ | 187 | ||||||
The net
increase in the total amount of unrecognized tax benefits during 2009 is
primarily related to the tax normalization issue described in Note 3(b) to our
consolidated financial statements, a change in tax accounting method for repairs
and maintenance of our network assets and a casualty loss deduction associated
with Hurricane
103
Ike. These
three uncertain income tax positions are temporary differences and therefore,
any increase or decrease in the balance of unrecognized tax benefits related
thereto would not affect the effective tax rate. It is reasonably
possible that the total amount of unrecognized tax benefits could increase
between $22 million and $65 million over the next 12 months primarily
as a result of the tax normalization issue, a temporary
difference.
CenterPoint
Energy has approximately $10 million, $14 million and $10 million
of unrecognized tax benefits that, if recognized, would reduce the effective
income tax rate for 2007, 2008 and 2009, respectively. CenterPoint Energy
recognizes interest and penalties as a component of income tax expense.
CenterPoint Energy recognized approximately $3 million and $6 million
of income tax expense and $7 million of income tax benefit related to
interest on uncertain income tax positions during 2007, 2008 and 2009,
respectively. CenterPoint Energy accrued $10 million and $3 million of
interest on uncertain income tax positions at December 31, 2008 and 2009,
respectively.
Tax Audits and
Settlements. CenterPoint Energy’s consolidated federal income
tax returns have been audited and settled through the 2005 tax year. CenterPoint
Energy is currently under examination by the IRS for tax years 2006 through 2007
and is at various stages of the examination process. CenterPoint Energy has
considered the effects of these examinations in its accrual for settled issues
and liability for uncertain income tax positions as of December 31,
2009.
(10) Commitments
and Contingencies
(a)
Natural Gas Supply Commitments
Natural
gas supply commitments include natural gas contracts related to CenterPoint
Energy’s Natural Gas Distribution and Competitive Natural Gas Sales and Services
business segments, which have various quantity requirements and durations, that
are not classified as non-trading derivative assets and liabilities in
CenterPoint Energy’s Consolidated Balance Sheets as of December 31, 2008
and 2009 as these contracts meet the exception to be classified as "normal
purchases contracts" or do not meet the definition of a derivative. Natural gas
supply commitments also include natural gas transportation contracts that do not
meet the definition of a derivative. As of December 31, 2009, minimum
payment obligations for natural gas supply commitments are approximately
$439 million in 2010, $490 million in 2011, $427 million in 2012,
$390 million in 2013, $269 million in 2014 and $543 million after
2014.
(b)
Asset Management Agreements
Gas
Operations has entered into asset management agreements associated with its
utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and
Texas. Generally, these asset management agreements are contracts between Gas
Operations and an asset manager that are intended to transfer the working
capital obligation and maximize the utilization of the assets. In
these agreements, Gas Operations agreed to release transportation and storage
capacity to other parties to manage gas storage, supply and delivery
arrangements for Gas Operations and to use the released capacity for other
purposes when it is not needed for Gas Operations. Gas Operations is
compensated by the asset manager through payments made over the life of the
agreements based in part on the results of the asset optimization. Under the
provisions of these asset management agreements, Gas Operations has an
obligation to purchase its winter storage requirements from the asset manager.
The agreements have varying terms, the longest of which expires in
2016.
(c)
Lease Commitments
The
following table sets forth information concerning CenterPoint Energy’s
obligations under non-cancelable long-term operating leases at December 31,
2009, which primarily consist of rental agreements for building space, data
processing equipment and vehicles (in millions):
|
2010
|
$ | 12 | ||
|
2011
|
13 | |||
|
2012
|
9 | |||
|
2013
|
6 | |||
|
2014
|
4 | |||
|
2015
and beyond
|
7 | |||
|
Total
|
$ | 51 |
Total
lease expense for all operating leases was $48 million, $46 million
and $37 million during 2007, 2008 and 2009, respectively.
(d)
Other Commitments
In
December 2008, CenterPoint Energy entered into an agreement to purchase software
licenses, support and maintenance over the next five years. As of
December 31, 2009, payment obligations under this agreement are $7 million
in 2010, $6 million in 2011, $6 million in 2012 and $6 million in
2013.
Long-Term Gas Gathering and Treating
Agreements. In September 2009, CenterPoint Energy Field Services, Inc.
(CEFS), a wholly-owned natural gas gathering and treating subsidiary of CERC
Corp., entered into long-term agreements with an indirect wholly-owned
subsidiary of EnCana Corporation (EnCana) and an indirect wholly-owned
subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating
services for their natural gas production from certain Haynesville Shale and
Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned
gathering facilities from EnCana and Shell in De Soto and Red River parishes in
northwest Louisiana. Each of the agreements includes acreage
dedication and volume commitments for which CEFS has rights to gather Shell’s
and EnCana’s natural gas production from the dedicated areas.
In
connection with the agreements, CEFS commenced gathering and treating services
utilizing the acquired facilities. CEFS is expanding the acquired facilities in
order to gather and treat up to 700 million cubic feet (MMcf) per day of
natural gas. If EnCana or Shell elect, CEFS will further expand the facilities
in order to gather and treat additional future volumes. The
construction necessary to reach the contractual capacity of 700 MMcf per day
includes more than 200 miles of gathering lines, nearly 25,500 horsepower of
compression and over 800 MMcf per day of treating capacity.
CEFS
estimates that the purchase of existing facilities and construction to gather
700 MMcf per day will cost up to $325 million. If EnCana and Shell elect
expansion of the project to gather and process additional future volumes of up
to 1 Bcf per day, CEFS estimates that the expansion would cost as much as
an additional $300 million and EnCana and Shell would provide incremental
volume commitments. Funds for construction are being provided from anticipated
cash flows from operations, lines of credit or proceeds from the sale of debt or
equity securities. As of December 31, 2009, approximately
$176 million has been spent on this project, including the purchase of
existing facilities.
(e)
Legal, Environmental and Other Regulatory Matters
Legal
Matters
Gas Market Manipulation
Cases. CenterPoint Energy, CenterPoint Houston or their
predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their
former subsidiaries are named as defendants in several lawsuits described below.
Under a master separation agreement between CenterPoint Energy and RRI (formerly
known as Reliant Resources, Inc. and Reliant Energy, Inc.), CenterPoint Energy
and its subsidiaries are entitled to be indemnified by RRI for any losses,
including attorneys’ fees and other costs, arising out of these
lawsuits. Pursuant
105
to the
indemnification obligation, RRI is defending CenterPoint Energy and its
subsidiaries to the extent named in these lawsuits. A large number of
lawsuits were filed against numerous gas market participants in a number of
federal and western state courts in connection with the operation of the natural
gas markets in 2000-2002. CenterPoint Energy’s former affiliate, RRI, was a
participant in gas trading in the California and Western markets. These
lawsuits, many of which have been filed as class actions, allege violations of
state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a
variety of forms of relief, including, among others, recovery of compensatory
damages (in some cases in excess of $1 billion), a trebling of compensatory
damages, full consideration damages and attorneys’ fees. CenterPoint Energy
and/or Reliant Energy were named in approximately 30 of these lawsuits, which
were instituted between 2003 and 2009. CenterPoint Energy and its affiliates
have been released or dismissed from all but two of such cases. CenterPoint
Energy Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant in a
case now pending in federal court in Nevada alleging a conspiracy to inflate
Wisconsin natural gas prices in 2000-2002. Additionally, CenterPoint
Energy was a defendant in a lawsuit filed in state court in Nevada that was
dismissed in 2007, but the plaintiffs have indicated that they will appeal the
dismissal. CenterPoint Energy believes that neither it nor CES is a proper
defendant in these remaining cases and will continue to pursue dismissal from
those cases. CenterPoint Energy does not expect the ultimate outcome
of these remaining matters to have a material impact on its financial condition,
results of operations or cash flows.
On May 1,
2009, RRI completed the previously announced sale of its Texas retail business
to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection
with the sale, RRI changed its name to RRI Energy, Inc. and no longer provides
service as a REP in CenterPoint Houston’s service territory. The sale
does not alter RRI’s contractual obligations to indemnify CenterPoint Energy and
its subsidiaries, including CenterPoint Houston, for certain liabilities,
including their indemnification regarding certain litigation, nor does it affect
the terms of existing guaranty arrangements for certain RRI gas transportation
contracts.
Natural Gas Measurement
Lawsuits. CERC Corp. and certain of its subsidiaries, along with 76 other
natural gas pipelines, their subsidiaries and affiliates, were defendants in a
lawsuit filed in 1997 under the Federal False Claims Act alleging mismeasurement
of natural gas produced from federal and Indian lands. The suit sought
undisclosed damages, along with statutory penalties, interest, costs and fees.
This case was consolidated, together with the other similar False Claims Act
cases, in the federal district court in Cheyenne, Wyoming. In October 2006, the
judge considering this matter granted the defendants’ motion to dismiss the suit
on the ground that the court lacked subject matter jurisdiction over the claims
asserted. The plaintiff sought review of that dismissal from the Tenth Circuit
Court of Appeals, which affirmed the district court’s dismissal in March 2009.
Following dismissal of the plaintiff’s motion to the Tenth Circuit for
rehearing, the plaintiff sought review by the United States Supreme Court, but
his petition for certiorari was denied in October 2009.
In
addition, CERC Corp. and certain of its subsidiaries are defendants in two
mismeasurement lawsuits brought against approximately 245 pipeline companies and
their affiliates pending in state court in Stevens County, Kansas. In
one case (originally filed in May 1999 and amended four times), the plaintiffs
purport to represent a class of royalty owners who allege that the defendants
have engaged in systematic mismeasurement of the volume of natural gas for more
than 25 years. The plaintiffs amended their petition in this suit in July 2003
in response to an order from the judge denying certification of the plaintiffs’
alleged class. In the amendment, the plaintiffs dismissed their claims against
certain defendants (including two CERC Corp. subsidiaries), limited the scope of
the class of plaintiffs they purport to represent and eliminated previously
asserted claims based on mismeasurement of the British thermal unit (Btu)
content of the gas. The same plaintiffs then filed a second lawsuit, again as
representatives of a putative class of royalty owners in which they assert their
claims that the defendants have engaged in systematic mismeasurement of the Btu
content of natural gas for more than 25 years. In both lawsuits, the plaintiffs
seek compensatory damages, along with statutory penalties, treble damages,
interest, costs and fees. In September 2009, the district court in
Stevens County, Kansas, denied plaintiffs’ request for class certification of
their case. The plaintiffs are seeking reconsideration of that
denial.
CERC
believes that there has been no systematic mismeasurement of gas and that these
lawsuits are without merit. CERC and CenterPoint Energy do not expect the
ultimate outcome of the lawsuits to have a material impact on the financial
condition, results of operations or cash flows of either CenterPoint Energy or
CERC.
Gas Cost Recovery Litigation.
In October 2004, a lawsuit was filed by certain CERC ratepayers in Texas
and Arkansas in circuit court in Miller County, Arkansas against CenterPoint
Energy, CERC Corp., certain other
106
subsidiaries
of CenterPoint Energy and CERC Corp. and various non-affiliated companies
alleging fraud, unjust enrichment and civil conspiracy with respect to rates
charged to certain consumers of natural gas in Arkansas, Louisiana, Minnesota,
Mississippi, Oklahoma and Texas. Although the plaintiffs in the Miller County
case sought class certification, no class was certified. In June 2007, the
Arkansas Supreme Court determined that the Arkansas claims were within the sole
and exclusive jurisdiction of the Arkansas Public Service Commission (APSC) and
in February 2008, the Arkansas Supreme Court directed the Miller County court to
dismiss the entire case for lack of jurisdiction.
In August
2007, the Arkansas plaintiff in the Miller County litigation initiated a
complaint at the APSC seeking a decision concerning the extent of the APSC’s
jurisdiction over the Miller County case and an investigation into the merits of
the allegations asserted in his complaint with respect to CERC. In February
2009, the Arkansas plaintiff notified the APSC that he would no longer pursue
his claims, and in July 2009 the complaint proceeding was dismissed by the APSC.
All appellate deadlines expired without an appeal of the dismissal
order.
In June
2007, CenterPoint Energy, CERC Corp., and other defendants in the Miller County
case filed a petition in a district court in Travis County, Texas seeking a
determination that the Railroad Commission has exclusive original jurisdiction
over the Texas claims asserted in the Miller County case. In January
2009, the district court entered a final declaratory judgment ruling that the
Railroad Commission has exclusive jurisdiction over the Texas claims asserted
against CenterPoint Energy, and the other defendants in the Miller County
case.
Environmental
Matters
Manufactured Gas Plant Sites.
CERC and its predecessors operated manufactured gas plants (MGPs) in the past.
In Minnesota, CERC has completed remediation on two sites, other than ongoing
monitoring and water treatment. There are five remaining sites in CERC’s
Minnesota service territory. CERC believes that it has no liability with respect
to two of these sites.
At
December 31, 2009, CERC had accrued $14 million for remediation of
these Minnesota sites and the estimated range of possible remediation costs for
these sites was $4 million to $35 million based on remediation
continuing for 30 to 50 years. The cost estimates are based on studies of a site
or industry average costs for remediation of sites of similar size. The actual
remediation costs will be dependent upon the number of sites to be remediated,
the participation of other potentially responsible parties (PRP), if any, and
the remediation methods used. CERC has utilized an environmental expense tracker
mechanism in its rates in Minnesota to recover estimated costs in excess of
insurance recovery. As of December 31, 2009, CERC had collected
$13 million from insurance companies and rate payers to be used for future
environmental remediation. In January 2010, as part of its Minnesota rate case
decision, the MPUC eliminated the environmental expense tracker mechanism and
ordered amounts previously collected from ratepayers and related carrying costs
refunded to customers. As of December 31, 2009, the balance in the
environmental expense tracker account was $8.7 million. The MPUC
provided for the inclusion in rates of approximately $285,000 annually to fund
normal on-going remediation costs. CERC was not required to refund to
customers the amount collected from insurance companies, $4.6 million at
December 31, 2009, to be used to mitigate future environmental
costs. The MPUC further gave assurance that any reasonable and
prudent environmental clean-up costs CERC incurs in the future will be
rate-recoverable under normal regulatory principles and
procedures. This provision had no impact on earnings.
In
addition to the Minnesota sites, the United States Environmental Protection
Agency and other regulators have investigated MGP sites that were owned or
operated by CERC or may have been owned by one of its former affiliates. CERC
has been named as a defendant in a lawsuit filed in the United States District
Court, District of Maine, under which contribution is sought by private parties
for the cost to remediate former MGP sites based on the previous ownership of
such sites by former affiliates of CERC or its divisions. CERC has also been
identified as a PRP by the State of Maine for a site that is the subject of the
lawsuit. In June 2006, the federal district court in Maine ruled that the
current owner of the site is responsible for site remediation but that an
additional evidentiary hearing would be required to determine if other
potentially responsible parties, including CERC, would have to contribute to
that remediation. In September 2009, the federal district court granted CERC’s
motion for summary judgment in the proceeding. Although it is likely
that the plaintiff will pursue an appeal from that dismissal, further action
will not be taken until the district court disposes of claims against other
defendants in the case. CERC believes it is not liable as a former owner or
operator of the site under the Comprehensive Environmental,
Response,
107
Compensation
and Liability Act of 1980, as amended, and applicable state statutes, and is
vigorously contesting the suit and its designation as a PRP. CERC and
CenterPoint Energy do not expect the ultimate outcome to have a material adverse
impact on the financial condition, results of operations or cash flows of either
CenterPoint Energy or CERC.
Mercury Contamination.
CenterPoint Energy’s pipeline and distribution operations have in the past
employed elemental mercury in measuring and regulating equipment. It is possible
that small amounts of mercury may have been spilled in the course of normal
maintenance and replacement operations and that these spills may have
contaminated the immediate area with elemental mercury. CenterPoint Energy has
found this type of contamination at some sites in the past, and CenterPoint
Energy has conducted remediation at these sites. It is possible that other
contaminated sites may exist and that remediation costs may be incurred for
these sites. Although the total amount of these costs is not known at this time,
based on CenterPoint Energy’s experience and that of others in the natural gas
industry to date and on the current regulations regarding remediation of these
sites, CenterPoint Energy believes that the costs of any remediation of these
sites will not be material to CenterPoint Energy’s financial condition, results
of operations or cash flows.
Asbestos. Some facilities
owned by CenterPoint Energy contain or have contained asbestos insulation and
other asbestos-containing materials. CenterPoint Energy or its subsidiaries have
been named, along with numerous others, as a defendant in lawsuits filed by a
number of individuals who claim injury due to exposure to asbestos. Some of the
claimants have worked at locations owned by CenterPoint Energy, but most
existing claims relate to facilities previously owned by CenterPoint Energy’s
subsidiaries. CenterPoint Energy anticipates that additional claims like those
received may be asserted in the future. In 2004, CenterPoint Energy sold its
generating business, to which most of these claims relate, to Texas Genco LLC,
which is now known as NRG Texas LP. Under the terms of the arrangements
regarding separation of the generating business from CenterPoint Energy and its
sale to NRG Texas LP, ultimate financial responsibility for uninsured losses
from claims relating to the generating business has been assumed by NRG Texas
LP, but CenterPoint Energy has agreed to continue to defend such claims to the
extent they are covered by insurance maintained by CenterPoint Energy, subject
to reimbursement of the costs of such defense from NRG Texas LP. Although their
ultimate outcome cannot be predicted at this time, CenterPoint Energy intends to
continue vigorously contesting claims that it does not consider to have merit
and does not expect, based on its experience to date, these matters, either
individually or in the aggregate, to have a material adverse effect on
CenterPoint Energy’s financial condition, results of operations or cash
flows.
Groundwater Contamination
Litigation. Predecessor entities of CERC, along with several other
entities, are defendants in litigation, St. Michel Plantation, LLC, et al,
v. White, et al., pending in civil district court in Orleans Parish,
Louisiana. In the lawsuit, the plaintiffs allege that their property in
Terrebonne Parish, Louisiana suffered salt water contamination as a result of
oil and gas drilling activities conducted by the defendants. Although a
predecessor of CERC held an interest in two oil and gas leases on a portion of
the property at issue, neither it nor any other CERC entities drilled or
conducted other oil and gas operations on those leases. In January 2009,
CERC and the plaintiffs reached agreement on the terms of a settlement that, if
ultimately approved by the Louisiana Department of Natural Resources, is
expected to resolve this litigation. CenterPoint Energy and CERC do not expect
the outcome of this litigation to have a material adverse impact on the
financial condition, results of operations or cash flows of either CenterPoint
Energy or CERC.
Other Environmental. From
time to time CenterPoint Energy has received notices from regulatory authorities
or others regarding its status as a PRP in connection with sites found to
require remediation due to the presence of environmental contaminants. In
addition, CenterPoint Energy has been named from time to time as a defendant in
litigation related to such sites. Although the ultimate outcome of such matters
cannot be predicted at this time, CenterPoint Energy does not expect, based on
its experience to date, these matters, either individually or in the aggregate,
to have a material adverse effect on CenterPoint Energy’s financial condition,
results of operations or cash flows.
Other
Proceedings
CenterPoint
Energy is involved in other legal, environmental, tax and regulatory proceedings
before various courts, regulatory commissions and governmental agencies
regarding matters arising in the ordinary course of business. Some of these
proceedings involve substantial amounts. CenterPoint Energy regularly analyzes
current
108
information
and, as necessary, provides accruals for probable liabilities on the eventual
disposition of these matters. CenterPoint Energy does not expect the disposition
of these matters to have a material adverse effect on CenterPoint Energy’s
financial condition, results of operations or cash flows.
In
December 2009, $3.3 million was distributed to a subsidiary of CenterPoint
Energy in connection with the settlement of 2002 AOL Time Warner, Inc.
securities and ERISA class action litigation. Pursuant to the terms of the
indenture governing CenterPoint Energy’s ZENS, in February 2010, CenterPoint
Energy distributed to current ZENS holders $2.8 million, which amount
represented the portion of the payment received that was attributable to the
reference shares corresponding to the outstanding ZENS. This distribution
reduced the contingent principal amount of the ZENS from $814 million to
$811 million. The litigation settlement was recorded as other income
and the distribution payable to ZENS holders was recorded as other expense in
2009.
(f)
Guaranties
Prior to
CenterPoint Energy’s distribution of its ownership in RRI to its shareholders,
CERC had guaranteed certain contractual obligations of what became RRI’s trading
subsidiary. When the companies separated, RRI agreed to secure CERC
against obligations under the guaranties RRI had been unable to extinguish by
the time of separation. Pursuant to such agreement, as amended in December
2007, RRI has agreed to provide to CERC cash or letters of credit
as security against CERC’s obligations under its remaining guaranties for
demand charges under certain gas transportation agreements if and to the extent
changes in market conditions expose CERC to a risk of loss on those
guaranties. The present value of the demand charges under these
transportation contracts, which will be effective until 2018, was approximately
$96 million as of December 31, 2009. As of December 31, 2009, RRI was
not required to provide security to CERC. If RRI should fail to perform
the contractual obligations, CERC could have to honor its guarantee and, in such
event, collateral provided as security may be insufficient to satisfy CERC’s
obligations.
(11) Estimated
Fair Value of Financial Instruments
The fair
values of cash and cash equivalents, investments in debt and equity securities
classified as "available-for-sale" and "trading" and short-term borrowings are
estimated to be approximately equivalent to carrying amounts and have been
excluded from the table below. The fair values of non-trading derivative assets
and liabilities and the ZENS indexed debt securities derivative are stated at
fair value and are excluded from the table below. The fair value of
each debt instrument is determined by multiplying the principal amount of each
debt instrument by the market price.
|
December 31,
2008
|
December 31,
2009
|
|||||||||||||||
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|||||||||||||
|
(in
millions)
|
||||||||||||||||
|
Financial
liabilities:
|
||||||||||||||||
|
Long-term
debt
|
$ | 10,396 | $ | 9,875 | $ | 9,900 | $ | 10,413 | ||||||||
(12) Earnings
Per Share
The
following table reconciles numerators and denominators of CenterPoint Energy’s
basic and diluted earnings per share calculations:
|
For
the Year Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
(In
millions, except per share and share amounts)
|
||||||||||||
|
Basic
earnings per share calculation:
|
||||||||||||
|
Net
income
|
$ | 395 | $ | 446 | $ | 372 | ||||||
|
Weighted
average shares outstanding
|
320,480,000 | 336,387,000 | 365,229,000 | |||||||||
|
Basic
earnings per share
|
$ | 1.23 | $ | 1.32 | $ | 1.02 | ||||||
|
Diluted
earnings per share calculation:
|
||||||||||||
|
Net
income
|
$ | 395 | $ | 446 | $ | 372 | ||||||
|
Weighted
average shares outstanding
|
320,480,000 | 336,387,000 | 365,229,000 | |||||||||
|
Plus:
Incremental shares from assumed conversions:
|
||||||||||||
|
Stock
options(1)
|
1,059,000 | 760,000 | 451,000 | |||||||||
|
Restricted
stock
|
1,928,000 | 1,772,000 | 2,001,000 | |||||||||
|
2.875% convertible
senior notes
|
291,000 | - | - | |||||||||
|
3.75% convertible
senior notes
|
18,749,000 | 4,636,000 | - | |||||||||
|
Weighted
average shares assuming dilution
|
342,507,000 | 343,555,000 | 367,681,000 | |||||||||
|
Diluted
earnings per share
|
$ | 1.15 | $ | 1.30 | $ | 1.01 | ||||||
|
|
(1)
|
Options
to purchase 3,225,969, 2,617,772 and 2,372,132 shares were
outstanding for the years ended December 31, 2007, 2008 and 2009,
respectively, but were not included in the computation of diluted earnings
per share because the options’ exercise price was greater than the average
market price of the common shares for the respective
years.
|
Substantially
all of the 3.75% contingently convertible senior notes provided for settlement
of the principal portion in cash rather than stock. The portion of the
conversion value of such notes that was required to be settled in cash rather
than stock is excluded from the computation of diluted earnings per share from
continuing operations. CenterPoint Energy included the conversion spread in the
calculation of diluted earnings per share when the average market price of
CenterPoint Energy’s common stock in the respective reporting period exceeded
the conversion price. In April 2008, CenterPoint
Energy called its 3.75% convertible senior notes for redemption on May 30,
2008. Substantially all of CenterPoint Energy’s 3.75% convertible senior notes
were submitted for conversion on or prior to the May 30, 2008 redemption
date.
(13) Unaudited
Quarterly Information
Summarized
quarterly financial data is as follows:
|
Year
Ended December 31, 2008
|
||||||||||||||||
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
|||||||||||||
|
(In
millions, except per share amounts)
|
||||||||||||||||
|
Revenues
|
$ | 3,363 | $ | 2,670 | $ | 2,515 | $ | 2,774 | ||||||||
|
Operating
income
|
336 | 297 | 337 | 303 | ||||||||||||
|
Net
income
|
122 | 101 | 136 | 87 | ||||||||||||
|
Basic
earnings per share(1)
|
$ | 0.37 | $ | 0.30 | $ | 0.40 | $ | 0.25 | ||||||||
|
Diluted
earnings per share(1)
|
$ | 0.36 | $ | 0.30 | $ | 0.39 | $ | 0.25 | ||||||||
|
Year
Ended December 31, 2009
|
||||||||||||||||
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
|||||||||||||
|
(In
millions, except per share amounts)
|
||||||||||||||||
|
Revenues
|
$ | 2,766 | $ | 1,640 | $ | 1,576 | $ | 2,299 | ||||||||
|
Operating
income
|
285 | 253 | 287 | 299 | ||||||||||||
|
Net
income
|
67 | 86 | 114 | 105 | ||||||||||||
|
Basic
earnings per share(1)
|
$ | 0.19 | $ | 0.24 | $ | 0.31 | $ | 0.27 | ||||||||
|
Diluted
earnings per share(1)
|
$ | 0.19 | $ | 0.24 | $ | 0.31 | $ | 0.27 | ||||||||
_________
|
|
(1)
|
Quarterly
earnings per common share are based on the weighted average number of
shares outstanding during the quarter, and the sum of the quarters may not
equal annual earnings per common share. CenterPoint Energy included the
conversion spread related to its contingently convertible senior notes in
the calculation of diluted earnings per share when the average market
price of CenterPoint Energy’s common stock in the respective reporting
period exceeds the conversion price. All of CenterPoint Energy’s 3.75%
convertible senior notes were submitted for conversion on or prior to the
May 30, 2008 redemption
date.
|
(14) Reportable
Business Segments
CenterPoint
Energy’s determination of reportable business segments considers the strategic
operating units under which CenterPoint Energy manages sales, allocates
resources and assesses performance of various products and services to wholesale
or retail customers in differing regulatory environments. The accounting
policies of the business segments are the same as those described in the summary
of significant accounting policies except that some executive benefit costs have
not been allocated to business segments. CenterPoint Energy uses operating
income as the measure of profit or loss for its business segments.
CenterPoint
Energy’s reportable business segments include the following: Electric
Transmission & Distribution, Natural Gas Distribution, Competitive Natural
Gas Sales and Services, Interstate Pipelines, Field Services and Other
Operations. The electric transmission and distribution function (CenterPoint
Houston) is reported in the Electric Transmission & Distribution business
segment. Natural Gas Distribution consists of intrastate natural gas sales to,
and natural gas transportation and distribution for, residential, commercial,
industrial and institutional customers. Competitive Natural Gas Sales and
Services represents CenterPoint Energy’s non-rate regulated gas sales and
services operations, which consist of three operational functions: wholesale,
retail and intrastate pipelines. The Interstate Pipelines business segment
includes the interstate natural gas pipeline operations. The Field Services
business segment includes the natural gas gathering, treating and processing
operations. Other Operations consists primarily of other corporate operations
which support all of CenterPoint Energy’s business operations.
Long-lived
assets include net property, plant and equipment, net goodwill and other
intangibles and equity investments in unconsolidated subsidiaries. Intersegment
sales are eliminated in consolidation.
Financial
data for business segments and products and services are as follows (in
millions):
|
Revenues
from
External
Customers
|
Intersegment
Revenues
|
Depreciation
and
Amortization
|
Operating
Income
(Loss)
|
Total
Assets
|
Expenditures
for
Long-Lived
Assets
|
|||||||||||||||||||
|
As
of and for the year ended
December 31,
2007:
|
||||||||||||||||||||||||
|
Electric
Transmission & Distribution
|
$ | 1,837 | (1) | $ | - | $ | 398 | $ | 561 | $ | 8,358 | $ | 401 | |||||||||||
|
Natural
Gas Distribution
|
3,749 | 10 | 155 | 218 | 4,332 | 191 | ||||||||||||||||||
|
Competitive
Natural Gas Sales and Services
|
3,534 | 45 | 5 | 75 | 1,221 | 7 | ||||||||||||||||||
|
Interstate
Pipelines(2)
|
357 | 143 | 44 | 237 | 3,007 | 308 | ||||||||||||||||||
|
Field
Services(3)
|
136 | 39 | 11 | 99 | 669 | 74 | ||||||||||||||||||
|
Other
|
10 | - | 18 | (5 | ) | 1,956 | (4) | 30 | ||||||||||||||||
|
Reconciling
Eliminations
|
- | (237 | ) | - | - | (1,671 | ) | - | ||||||||||||||||
|
Consolidated
|
$ | 9,623 | $ | - | $ | 631 | $ | 1,185 | $ | 17,872 | $ | 1,011 | ||||||||||||
|
As
of and for the year ended
December 31,
2008:
|
||||||||||||||||||||||||
|
Electric
Transmission & Distribution
|
$ | 1,916 | (1) | $ | - | $ | 460 | $ | 545 | $ | 8,880 | $ | 481 | (5) | ||||||||||
|
Natural
Gas Distribution
|
4,217 | 9 | 157 | 215 | 4,961 | 214 | ||||||||||||||||||
|
Competitive
Natural Gas Sales and Services
|
4,488 | 40 | 3 | 62 | 1,315 | 8 | ||||||||||||||||||
|
Interstate
Pipelines(2)
|
477 | 173 | 46 | 293 | 3,578 | 189 | ||||||||||||||||||
|
Field
Services(3)
|
213 | 39 | 12 | 147 | 826 | 122 | ||||||||||||||||||
|
Other
|
11 | - | 30 | 11 | 2,185 | (4) | 39 | |||||||||||||||||
|
Reconciling
Eliminations
|
- | (261 | ) | - | - | (2,069 | ) | - | ||||||||||||||||
|
Consolidated
|
$ | 11,322 | $ | - | $ | 708 | $ | 1,273 | $ | 19,676 | $ | 1,053 | ||||||||||||
|
As
of and for the year ended
December 31,
2009:
|
||||||||||||||||||||||||
|
Electric
Transmission & Distribution
|
$ | 2,013 | (1) | $ | - | $ | 480 | $ | 545 | $ | 9,755 | $ | 428 | (5) | ||||||||||
|
Natural
Gas Distribution
|
3,374 | 10 | 161 | 204 | 4,535 | 165 | ||||||||||||||||||
|
Competitive
Natural Gas Sales and Services
|
2,215 | 15 | 4 | 21 | 1,176 | 2 | ||||||||||||||||||
|
Interstate
Pipelines(2)
|
456 | 142 | 48 | 256 | 3,484 | 176 | ||||||||||||||||||
|
Field
Services(3)
|
212 | 29 | 15 | 94 | 1,045 | 348 | ||||||||||||||||||
|
Other
|
11 | - | 35 | 4 | 2,261 | (4) | 29 | |||||||||||||||||
|
Reconciling
Eliminations
|
- | (196 | ) | - | - | (2,483 | ) | - | ||||||||||||||||
|
Consolidated
|
$ | 8,281 | $ | - | $ | 743 | $ | 1,124 | $ | 19,773 | $ | 1,148 | ||||||||||||
|
|
(1)
|
Sales
to subsidiaries of NRG Retail LLC, the successor to RRI’s Texas retail
business, in 2007, 2008 and 2009 represented approximately
$661 million, $635 million and $634 million, respectively,
of CenterPoint Houston’s transmission and distribution
revenues.
|
|
|
(2)
|
Interstate
Pipelines recorded equity income of $6 million, $36 million, and
$7 million (including $6 million and $33 million related to
pre-operating allowance for funds used during construction during 2007 and
2008, respectively) in the years ended December 31, 2007, 2008 and 2009,
respectively, from its 50% interest in SESH, a jointly-owned pipeline.
These amounts are included in Equity in earnings of unconsolidated
affiliates under the Other Income (Expense) caption. Interstate
Pipelines’ investment in SESH was $58 million, $307 million and
$422 million as of December 31, 2007, 2008 and 2009 and is included
in Investment in unconsolidated
affiliates.
|
|
|
(3)
|
Field
Services recorded equity income of $10 million, $15 million and
$8 million for the years ended December 31, 2007, 2008 and 2009,
respectively, from its 50% interest in a jointly-owned gas processing
plant. These amounts are included in Equity in earnings of unconsolidated
affiliates under the Other Income (Expense) caption. Field
Services’ investment in the jointly-owned gas processing plant was
$30 million, $38 million and $40 million as of December 31,
2007, 2008 and 2009, respectively, and is included in Investment in
unconsolidated affiliates.
|
|
|
(4)
|
Included
in total assets of Other Operations as of December 31, 2007 are
pension assets of $231 million. Also included in total assets of
Other Operations as of December 31, 2007, 2008 and 2009, are pension
and other postemployment related regulatory assets of $319 million,
$800 million and $731 million,
respectively.
|
|
|
(5)
|
Included
in expenditures for long-lived assets of Electric Transmission &
Distribution is $145 million and $26 million for 2008 and 2009,
respectively, related to Hurricane Ike. Approximately $153 million of
distribution related storm restoration costs was reclassified to
regulatory assets and was included in the $665 million securitized
storm restoration costs as further discussed in Note 3(a). The
remaining $18 million of transmission related storm restoration costs
is included in plant in service as of December 31, 2009, and is eligible
for recovery through the existing mechanisms established to recover
transmission costs as further discussed in Note
3(a).
|
|
Year
Ended December 31,
|
||||||||||||
|
Revenues
by Products and Services:
|
2007
|
2008
|
2009
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Electric
delivery sales
|
$ | 1,837 | $ | 1,916 | $ | 2,013 | ||||||
|
Retail
gas sales
|
4,941 | 6,216 | 4,540 | |||||||||
|
Wholesale
gas sales
|
2,196 | 2,295 | 902 | |||||||||
|
Gas
transport
|
532 | 756 | 691 | |||||||||
|
Energy
products and services
|
117 | 139 | 135 | |||||||||
|
Total
|
$ | 9,623 | $ | 11,322 | $ | 8,281 | ||||||
(15) Subsequent
Events
On
January 21, 2010, CenterPoint Energy’s board of directors declared a
regular quarterly cash dividend of $0.195 per share of common stock payable on
March 10, 2010, to shareholders of record as of the close of business on
February 16, 2010.
Item 9. Changes in and
Disagreements with Accountants on Accounting and Financial
Disclosure
None.
Item 9A. Controls and
Procedures
Disclosure
Controls And Procedures
In
accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our principal executive officer and principal financial officer, of
the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our principal executive
officer and principal financial officer concluded that our disclosure controls
and procedures were effective as of December 31, 2009 to provide assurance
that information required to be disclosed in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission’s rules and
forms and such information is accumulated and communicated to our management,
including our principal executive officer and principal financial officer, as
appropriate to allow timely decisions regarding disclosure.
There has
been no change in our internal controls over financial reporting that occurred
during the three months ended December 31, 2009 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.
Management’s
Annual Report on Internal Control over Financial Reporting
See
report set forth above in Item 8, "Financial Statements and Supplementary
Data."
Report
of Independent Registered Public Accounting Firm on Internal Control Over
Financial Reporting
See
report set forth above in Item 8, "Financial Statements and Supplementary
Data."
Item 9B.
Other
Information
None.
PART III
Item 10. Directors, Executive Officers and
Corporate Governance
The
information called for by Item 10, to the extent not set forth in
"Executive Officers" in Item 1, will be set forth in the definitive proxy
statement relating to CenterPoint Energy’s 2010 annual meeting of shareholders
pursuant to SEC Regulation 14A. Such definitive proxy statement relates to
a meeting of shareholders involving the election of directors and the portions
thereof called for by Item 10 are incorporated herein by reference pursuant
to Instruction G to Form 10-K.
Item 11. Executive
Compensation
The
information called for by Item 11 will be set forth in the definitive proxy
statement relating to CenterPoint Energy’s 2010 annual meeting of shareholders
pursuant to SEC Regulation 14A. Such definitive proxy statement relates to
a meeting of shareholders involving the election of directors and the portions
thereof called for by Item 11 are incorporated herein by reference pursuant
to Instruction G to Form 10-K.
Item 12. Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
The
information called for by Item 12 will be set forth in the definitive proxy
statement relating to CenterPoint Energy’s 2010 annual meeting of shareholders
pursuant to SEC Regulation 14A. Such definitive proxy statement relates to
a meeting of shareholders involving the election of directors and the portions
thereof called for by Item 12 are incorporated herein by reference pursuant
to Instruction G to Form 10-K.
Item 13. Certain
Relationships and Related Transactions, and Director Independence
The
information called for by Item 13 will be set forth in the definitive proxy
statement relating to CenterPoint Energy’s 2010 annual meeting of shareholders
pursuant to SEC Regulation 14A. Such definitive proxy statement relates to
a meeting of shareholders involving the election of directors and the portions
thereof called for by Item 13 are incorporated herein by reference pursuant
to Instruction G to Form 10-K.
Item 14. Principal Accounting Fees and
Services
The
information called for by Item 14 will be set forth in the definitive proxy
statement relating to CenterPoint Energy’s 2010 annual meeting of shareholders
pursuant to SEC Regulation 14A. Such definitive proxy statement relates to
a meeting of shareholders involving the election of directors and the portions
thereof called for by Item 14 are incorporated herein by reference pursuant
to Instruction G to Form 10-K.
PART IV
Item 15. Exhibits and Financial Statement
Schedules
(a)(1)
Financial Statements.
|
64
|
|
|
67
|
|
|
68
|
|
|
69
|
|
|
70
|
|
|
71
|
|
|
72
|
(a)(2)
Financial Statement Schedules for the Three Years Ended December 31,
2009.
|
Report
of Independent Registered Public Accounting Firm
|
116
|
|
117
|
|
|
123
|
The
following schedules are omitted because of the absence of the conditions under
which they are required or because the required information is included in the
financial statements:
III, IV
and V.
(a)(3)
Exhibits.
See Index
of Exhibits beginning on page 125, which index also includes the management
contracts or compensatory plans or arrangements required to be filed as exhibits
to this Form 10-K by Item 601(b)(10)(iii) of
Regulation S-K.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Shareholders of
CenterPoint
Energy, Inc.
Houston,
Texas
We have
audited the consolidated financial statements of CenterPoint Energy, Inc. and
subsidiaries (the "Company") as of December 31, 2009 and 2008, and for each of
the three years in the period ended December 31, 2009, and the Company's
internal control over financial reporting as of December 31, 2009, and have
issued our reports thereon dated February 26, 2010; such reports are included
elsewhere in this Form 10-K. Our audits also included the financial
statement schedules of the Company listed in the index at Item 15 (a)(2).
These financial statement schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion based on our
audits. In our opinion, such financial statement schedules, when
considered in relation to the basic consolidated financial statements taken as a
whole, present fairly, in all material respects, the information set forth
therein.
/s/
DELOITTE & TOUCHE LLP
Houston,
Texas
February 26,
2010
CENTERPOINT
ENERGY, INC.
CENTERPOINT
ENERGY, INC. (PARENT COMPANY)
STATEMENTS
OF INCOME
|
For
the Year Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Expenses:
|
||||||||||||
|
Operation
and Maintenance Expenses
|
$ | (17 | ) | $ | (12 | ) | $ | (17 | ) | |||
|
Taxes
Other than Income
|
(4 | ) | 1 | - | ||||||||
|
Total
|
(21 | ) | (11 | ) | (17 | ) | ||||||
|
Other
Income (Expense):
|
||||||||||||
|
Interest
Income from Subsidiaries
|
22 | 12 | 8 | |||||||||
|
Other
Income (Expense)
|
1 | (5 | ) | (2 | ) | |||||||
|
Gain
(Loss) on Indexed Debt Securities
|
111 | 128 | (68 | ) | ||||||||
|
Interest
Expense to Subsidiaries
|
(67 | ) | (38 | ) | (25 | ) | ||||||
|
Interest
Expense
|
(225 | ) | (162 | ) | (149 | ) | ||||||
|
Distribution
to ZENS Holders
|
(27 | ) | - | (3 | ) | |||||||
|
Total
|
(185 | ) | (65 | ) | (239 | ) | ||||||
|
Loss
Before Income Taxes
|
(206 | ) | (76 | ) | (256 | ) | ||||||
|
Income
Tax Benefit
|
86 | 32 | 113 | |||||||||
|
Loss
Before Equity in Subsidiaries
|
(120 | ) | (44 | ) | (143 | ) | ||||||
|
Equity
Income of Subsidiaries
|
515 | 490 | 515 | |||||||||
|
Net
Income
|
$ | 395 | $ | 446 | $ | 372 | ||||||
See
CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8
CENTERPOINT
ENERGY, INC.
SCHEDULE I -
CONDENSED FINANCIAL INFORMATION OF
CENTERPOINT
ENERGY, INC. (PARENT COMPANY)
BALANCE
SHEETS
|
December 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
(In
millions)
|
||||||||
|
ASSETS
|
||||||||
|
Current
Assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | - | $ | - | ||||
|
Notes
receivable - subsidiaries
|
82 | 493 | ||||||
|
Accounts
receivable - subsidiaries
|
53 | 72 | ||||||
|
Other
assets
|
- | 16 | ||||||
|
Total
current assets
|
135 | 581 | ||||||
|
Other
Assets:
|
||||||||
|
Investment
in subsidiaries
|
5,161 | 5,562 | ||||||
|
Notes
receivable - subsidiaries
|
151 | 151 | ||||||
|
Other
assets
|
826 | 751 | ||||||
|
Total
other assets
|
6,138 | 6,464 | ||||||
|
Total
Assets
|
$ | 6,273 | $ | 7,045 | ||||
|
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
||||||||
|
Current
Liabilities:
|
||||||||
|
Notes
payable - subsidiaries
|
$ | 21 | $ | 306 | ||||
|
Current
portion of long-term debt
|
117 | 611 | ||||||
|
Indexed
debt securities derivative
|
133 | 201 | ||||||
|
Accounts
payable:
|
||||||||
|
Subsidiaries
|
40 | 17 | ||||||
|
Other
|
3 | 40 | ||||||
|
Taxes
accrued
|
338 | 416 | ||||||
|
Interest
accrued
|
26 | 29 | ||||||
|
Other
|
18 | 1 | ||||||
|
Total
current liabilities
|
696 | 1,621 | ||||||
|
Other
Liabilities:
|
||||||||
|
Accumulated
deferred tax liabilities
|
138 | 122 | ||||||
|
Benefit
obligations
|
426 | 426 | ||||||
|
Notes
payable - subsidiaries
|
750 | 750 | ||||||
|
Other
|
7 | 7 | ||||||
|
Total
non-current liabilities
|
1,321 | 1,305 | ||||||
|
Long-Term
Debt
|
2,234 | 1,480 | ||||||
|
Shareholders’
Equity:
|
||||||||
|
Common
stock
|
3 | 4 | ||||||
|
Additional
paid-in capital
|
3,158 | 3,671 | ||||||
|
Accumulated
deficit
|
(1,008 | ) | (912 | ) | ||||
|
Accumulated
other comprehensive loss
|
(131 | ) | (124 | ) | ||||
|
Total
shareholders’ equity
|
2,022 | 2,639 | ||||||
|
Total
Liabilities and Shareholders’ Equity
|
$ | 6,273 | $ | 7,045 | ||||
See
CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8
CENTERPOINT
ENERGY, INC.
SCHEDULE I -
CONDENSED FINANCIAL INFORMATION OF
CENTERPOINT
ENERGY, INC. (PARENT COMPANY)
STATEMENTS
OF CASH FLOWS
|
For
the Year Ended December 31,
|
||||||||||||
|
2007
|
2008
|
2009
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Operating
Activities:
|
||||||||||||
|
Net
income
|
$ | 395 | $ | 446 | $ | 372 | ||||||
|
Non-cash
items included in net income:
|
||||||||||||
|
Equity
income of subsidiaries
|
(515 | ) | (490 | ) | (515 | ) | ||||||
|
Deferred
income tax expense
|
52 | 90 | (19 | ) | ||||||||
|
Amortization
of debt issuance costs
|
50 | 7 | 5 | |||||||||
|
Loss
(gain) on indexed debt securities
|
(111 | ) | (128 | ) | 68 | |||||||
|
Changes
in working capital:
|
||||||||||||
|
Accounts
receivable/(payable) from subsidiaries, net
|
20 | (65 | ) | 86 | ||||||||
|
Accounts
payable
|
11 | - | 14 | |||||||||
|
Other
current assets
|
- | 2 | (16 | ) | ||||||||
|
Other
current liabilities
|
(50 | ) | (111 | ) | 59 | |||||||
|
Common
stock dividends received from subsidiaries
|
240 | 746 | 109 | |||||||||
|
Other
|
2 | (7 | ) | (1 | ) | |||||||
|
Net
cash provided by operating activities
|
94 | 490 | 162 | |||||||||
|
Investing
Activities:
|
||||||||||||
|
Short-term
notes receivable from subsidiaries
|
175 | 134 | (411 | ) | ||||||||
|
Net
cash provided by (used in) investing activities
|
175 | 134 | (411 | ) | ||||||||
|
Financing
Activities:
|
||||||||||||
|
Revolving
credit facility, net
|
131 | 133 | (264 | ) | ||||||||
|
Proceeds
from long-term debt
|
250 | 300 | - | |||||||||
|
Payments
on long-term debt
|
(295 | ) | (907 | ) | - | |||||||
|
Debt
issuance costs
|
(2 | ) | (4 | ) | - | |||||||
|
Common
stock dividends paid
|
(218 | ) | (246 | ) | (276 | ) | ||||||
|
Proceeds
from issuance of common stock, net
|
22 | 80 | 504 | |||||||||
|
Short-term
notes payable to subsidiaries
|
(157 | ) | 20 | 285 | ||||||||
|
Net
cash provided by (used in) financing activities
|
(269 | ) | (624 | ) | 249 | |||||||
|
Net
Decrease in Cash and Cash Equivalents
|
- | - | - | |||||||||
|
Cash
and Cash Equivalents at Beginning of Year
|
- | - | - | |||||||||
|
Cash
and Cash Equivalents at End of Year
|
$ | - | $ | - | $ | - | ||||||
See
CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8
CENTERPOINT
ENERGY, INC.
SCHEDULE I -
NOTES TO CONDENSED FINANCIAL INFORMATION (PARENT COMPANY)
(1) Background. The condensed
parent company financial statements and notes should be read in conjunction with
the consolidated financial statements and notes of CenterPoint Energy, Inc.
(CenterPoint Energy) appearing in the Annual Report on Form 10-K. Bank
facilities at CenterPoint Energy Houston Electric, LLC and CenterPoint Energy
Resources Corp., indirect wholly owned subsidiaries of CenterPoint Energy, limit
debt, excluding transition and system restoration bonds, as a percentage of
their total capitalization to 65%. These covenants could restrict the ability of
these subsidiaries to distribute dividends to CenterPoint Energy.
(2) New Accounting Pronouncements.
Effective January 1, 2009, CenterPoint Energy adopted new accounting
guidance for convertible debt instruments that may be settled in cash upon
conversion (including partial cash settlement) which changed the accounting
treatment for convertible securities that the issuer may settle fully or
partially in cash and which required retrospective application to all periods
presented. Under this new guidance, cash settled convertible securities are
separated into their debt and equity components. The value assigned to the debt
component is the estimated fair value, as of the issuance date, of a similar
debt instrument without the conversion feature, and the difference between the
proceeds for the convertible debt and the amount reflected as a debt liability
is recorded as additional paid-in capital. As a result, the debt is recorded at
a discount reflecting its below-market coupon interest rate. The debt is then
subsequently accreted to its par value over its expected life, with the rate of
interest that reflects the market rate at issuance being reflected on the income
statement. CenterPoint Energy currently has no convertible debt that is within
the scope of this new guidance, but did during prior periods presented.
The required retrospective implementation of this new guidance had a non-cash
effect on net income for prior periods and the Consolidated Balance Sheets when
CenterPoint Energy had contingently convertible debt outstanding. The effect on
net income for the years ended December 31, 2007 and 2008 was a decrease in net
income of $4 million, or $0.02 per basic and diluted share, and
$1 million, or $0.01 per basic share and no change per diluted share,
respectively. The implementation effect on the Consolidated Balance Sheet as of
December 31, 2008 increased Additional Paid-In-Capital and Accumulated Deficit
by $23 million.
Effective
January 1, 2008, CenterPoint Energy adopted new guidance on accounting for
deferred compensation and postretirement benefit aspects of endorsement
split-dollar life insurance arrangements which required CenterPoint Energy to
recognize the effect of implementation through a cumulative effect adjustment to
retained earnings or other components of equity as of the beginning of the year
of adoption. CenterPoint Energy calculated the impact as negligible at the
time of adoption on January 1, 2008. During 2009, CenterPoint Energy
determined that its adoption calculation had omitted the impact that increasing
future premium costs would have on the liability and, therefore, it recorded as
a cumulative effect adjustment a $15 million correction to decrease
investment in subsidiaries and increase accumulated deficit as of January 1,
2008. The effect of the correction is not material to CenterPoint
Energy’s previously issued financial statements and did not affect CenterPoint
Energy’s results of operations or cash flows.
(3) Derivatives. In December 2007
and January 2008, CenterPoint Energy entered into treasury rate lock derivative
instruments (treasury rate locks) having an aggregate notional amount of
$300 million and a weighted-average locked U.S. treasury rate on ten-year
debt of 4.05%. These treasury rate locks were executed to hedge the ten-year
U.S. treasury rate expected to be used in pricing $300 million of
fixed-rate debt CenterPoint Energy planned to issue in 2008, because changes in
the U.S treasury rate would cause variability in CenterPoint Energy’s forecasted
interest payments. These treasury rate lock derivatives were designated as cash
flow hedges. Accordingly, unrealized gains and losses associated with the
treasury rate lock derivative instruments were recorded as a component of
accumulated other comprehensive income. In May 2008, CenterPoint Energy settled
its treasury rate locks for a payment of $7 million. The $7 million
loss recognized upon settlement of the treasury rate locks was recorded as a
component of accumulated other comprehensive loss and will be recognized as a
component of interest expense over the ten-year life of the related
$300 million senior notes issued in May 2008. Amortization of amounts
deferred in accumulated other comprehensive loss for the years ended December
31, 2008 and 2009 was less than $1 million. During the years ended
December 31, 2007 and 2008, CenterPoint Energy recognized a loss of
$2 million and $5 million, respectively, for these treasury rate locks
in accumulated other comprehensive loss. Ineffectiveness for the treasury rate
locks was not material during the years ended December 31, 2007 and
2008.
(4) Capital Stock. During the
year ended December 31, 2009, CenterPoint Energy received net proceeds of
approximately $280 million from the issuance of 24.2 million common
shares in an underwritten public offering, net proceeds of $148 million
from the issuance of 14.3 million common shares through a continuous
offering program, proceeds of approximately $57 million from the sale of
approximately 4.9 million common shares to CenterPoint Energy’s defined
contribution plan and proceeds of approximately $15 million from the sale
of approximately 1.3 million common shares to participants in CenterPoint
Energy’s enhanced dividend reinvestment plan.
(5) Long-term Debt. As of
December 31, 2009, CenterPoint Energy had no borrowings and approximately
$27 million of outstanding letters of credit under its $1.2 billion
credit facility. CenterPoint Energy had no commercial paper outstanding at
December 31, 2009. CenterPoint Energy was in compliance with all covenants
as of December 31, 2009.
CenterPoint
Energy’s $1.2 billion credit facility has a first drawn cost of the London
Interbank Offered Rate (LIBOR) plus 55 basis points based on CenterPoint
Energy’s current credit ratings. An additional utilization fee of 5 basis points
applies to borrowings any time more than 50% of the facility is utilized. The
spread to LIBOR and the utilization fee fluctuate based on the borrower’s credit
rating. The facility contains a debt (excluding transition and system
restoration bonds) to earnings before interest, taxes, depreciation and
amortization (EBITDA) covenant (as those terms are defined in the facility).
Such covenant was modified twice in 2008 to provide additional debt
capacity. The second modification was to provide debt capacity
pending the financing of system restoration costs following Hurricane
Ike. That modification was terminated with CenterPoint Houston’s
issuance of bonds to securitize such costs in November 2009. In
February 2010, CenterPoint Energy amended its credit facility to modify the
financial ratio covenant to allow for a temporary increase of the permitted
ratio of debt (excluding transition and system restoration bonds) to
EBITDA from 5 times to 5.5 times if CenterPoint Houston experiences
damage from a natural disaster in its service territory and CenterPoint Energy
certifies to the administrative agent that CenterPoint Houston has incurred
system restoration costs reasonably likely to exceed $100 million in a
calendar year, all or part of which CenterPoint Houston intends to seek to
recover through securitization financing. Such temporary increase in the
financial ratio covenant would be in effect from the date CenterPoint Energy
delivers its certification until the earliest to occur of (i) the completion of
the securitization financing, (ii) the first anniversary of CenterPoint Energy’s
certification or (iii) the revocation of such certification.
CenterPoint
Energy’s maturities of long-term debt, excluding the ZENS obligation, are
$490 million in 2010 and $19 million in 2011. There
are no maturities of long-term debt in 2012, 2013 and 2014. Maturities in 2010
include $290 million of pollution control bonds issued on behalf of
CenterPoint Energy which were purchased by CenterPoint Energy in January
2010.
(6) Guaranties. CenterPoint
Energy Services, Inc. (CES) provides comprehensive natural gas sales and
services to industrial and commercial customers. In order to hedge their
exposure to natural gas prices, CES has entered standard purchase and sale
agreements with various counterparties. CenterPoint Energy has guaranteed the
payment obligations of CES under certain of these agreements, typically for
one-year terms. As of December 31, 2009, CenterPoint Energy had guaranteed
$13 million under these agreements.
In
September 2009, CenterPoint Energy Field Services, Inc. (CEFS), an indirect
wholly-owned subsidiary of CenterPoint Energy, entered into long-term agreements
with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an
indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide
gathering and treating services for their natural gas production from certain
Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired
jointly-owned gathering facilities from EnCana and Shell in De Soto and Red
River parishes in northwest Louisiana. Each of the agreements includes
acreage dedication and volume commitments for which CEFS has rights to gather
Shell’s and EnCana’s natural gas production from the dedicated
areas.
In
connection with the agreements, CEFS commenced gathering and treating services
utilizing the acquired facilities. CEFS is expanding the acquired facilities in
order to gather and treat up to 700 million cubic feet (MMcf) per day of
natural gas. If EnCana or Shell elect, CEFS will further expand the facilities
in order to gather and treat additional future volumes. CenterPoint Energy has
guaranteed to fund CEFS’ obligations, including the initial expansion of the
facilities, under these long-term agreements. CenterPoint Energy’s initial
guarantee is for $200 million to both Shell and EnCana ($400 million
total), however the amount of the guarantee could increase if the
121
facilities
are expanded or additional services are added. The amount of the
guarantee reduces to $50 million upon completion of the gathering
system.
(7) Non-cash transactions. During
2008, CenterPoint Energy reduced its payables to subsidiaries, with no net asset
restrictions, by $430 million with a corresponding reduction in investment in
subsidiaries.
CENTERPOINT
ENERGY, INC.
For
the Three Years Ended December 31, 2009
|
Column
A
|
Column
B
|
Column C
|
Column
D
|
Column
E
|
||||||||||||||||
|
Description
|
Balance
at
Beginning
of
Period
|
Additions
|
Deductions
From
Reserves
(2)
|
Balance
at
End
of
Period
|
||||||||||||||||
|
Charged
to
Income
|
Charged
to
Other
Accounts
|
|||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
Year
Ended December 31, 2009:
|
||||||||||||||||||||
|
Accumulated
provisions:
|
||||||||||||||||||||
|
Uncollectible
accounts receivable
|
$ | 35 | $ | 36 | $ | - | $ | 47 | $ | 24 | ||||||||||
|
Deferred
tax asset valuation allowance
|
5 | - | - | - | 5 | |||||||||||||||
|
Year
Ended December 31, 2008:
|
||||||||||||||||||||
|
Accumulated
provisions:
|
||||||||||||||||||||
|
Uncollectible
accounts receivable
|
$ | 38 | $ | 54 | $ | 3 | $ | 60 | $ | 35 | ||||||||||
|
Deferred
tax asset valuation allowance
|
18 | (1 | ) | (12 | ) (1) | - | 5 | |||||||||||||
|
Year
Ended December 31, 2007:
|
||||||||||||||||||||
|
Accumulated
provisions:
|
||||||||||||||||||||
|
Uncollectible
accounts receivable
|
$ | 33 | $ | 45 | $ | - | $ | 40 | $ | 38 | ||||||||||
|
Deferred
tax asset valuation allowance
|
22 | (4 | ) | - | - | 18 | ||||||||||||||
__________
|
|
(1)
|
The
2008 change to the deferred tax asset valuation allowance charged to other
accounts represents a reduction equal to the related deferred tax asset
reduction in 2008 for re-measurement of state tax attributes, net of
federal tax benefit. A full valuation allowance for this deferred
tax asset was established in prior
periods.
|
|
|
(2)
|
Deductions
from reserves represent losses or expenses for which the respective
reserves were created. In the case of the uncollectible accounts reserve,
such deductions are net of recoveries of amounts previously written
off.
|
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized, in the City of Houston, the State
of Texas, on the 26th day of February, 2010.
|
CENTERPOINT
ENERGY, INC.
|
|
|
(Registrant)
|
|
|
By: /s/ David M.
McClanahan
|
|
|
David
M. McClanahan
|
|
|
President
and Chief Executive Officer
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities indicated on February 26, 2010.
|
Signature
|
Title
|
|
|
/s/ DAVID M.
MCCLANAHAN
|
President,
Chief Executive Officer and
|
|
|
David
M. McClanahan
|
Director
(Principal Executive Officer and Director)
|
|
|
/s/ GARY L.
WHITLOCK
|
Executive
Vice President and Chief
|
|
|
Gary
L. Whitlock
|
Financial
Officer (Principal Financial Officer)
|
|
|
/s/ WALTER L.
FITZGERALD
|
Senior
Vice President and Chief
|
|
|
Walter
L. Fitzgerald
|
Accounting
Officer (Principal Accounting Officer)
|
|
|
/s/ MILTON
CARROLL
|
Chairman
of the Board of Directors
|
|
|
Milton
Carroll
|
||
|
/s/ DONALD R.
CAMPBELL
|
Director
|
|
|
Donald
R. Campbell
|
||
|
/s/ DERRILL
CODY
|
Director
|
|
|
Derrill
Cody
|
||
|
/s/ O. HOLCOMBE
CROSSWELL
|
Director
|
|
|
O.
Holcombe Crosswell
|
||
|
/s/ MICHAEL
P. JOHNSON
|
Director
|
|
|
Michael
P. Johnson
|
||
|
/s/ JANIECE M.
LONGORIA
|
Director
|
|
|
Janiece
M. Longoria
|
||
|
/s/ THOMAS F.
MADISON
|
Director
|
|
|
Thomas
F. Madison
|
||
|
/s/ ROBERT T.
O’CONNELL
|
Director
|
|
|
Robert
T. O’Connell
|
||
|
/s/ SUSAN
O. RHENEY
|
Director
|
|
|
Susan
O. Rheney
|
||
|
/s/ MICHAEL E.
SHANNON
|
Director
|
|
|
Michael
E. Shannon
|
||
|
/s/ PETER S.
WAREING
|
Director
|
|
|
Peter
S. Wareing
|
||
|
/s/ SHERMAN
M. WOLFF
|
Director
|
|
|
Sherman
M. Wolff
|
||
CENTERPOINT
ENERGY, INC.
EXHIBITS TO
THE ANNUAL REPORT ON FORM 10-K
For
Fiscal Year Ended December 31, 2009
INDEX
OF EXHIBITS
Exhibits
included with this report are designated by a cross (†); all exhibits not so
designated are incorporated herein by reference to a prior filing as indicated.
Exhibits designated by an asterisk (*) are management contracts or compensatory
plans or arrangements required to be filed as exhibits to this Form 10-K by
Item 601(b)(10)(iii) of Regulation S-K. CenterPoint Energy has not
filed the exhibits and schedules to Exhibit 2. CenterPoint Energy hereby
agrees to furnish supplementally a copy of any schedule omitted from
Exhibit 2 to the SEC upon request.
The
agreements included as exhibits are included only to provide information to
investors regarding their terms. The agreements listed below may
contain representations, warranties and other provisions that were made, among
other things, to provide the parties thereto with specified rights and
obligations and to allocate risk among them, and such agreements should not be
relied upon as constituting or providing any factual disclosures about us, any
other persons, any state of affairs or other matters.
|
Exhibit
Number
|
Description
|
Report
or Registration Statement
|
SEC
File or
Registration
Number
|
Exhibit
Reference
|
||||
|
2
|
-
|
Transaction
Agreement dated July 21, 2004 among CenterPoint Energy, Utility
Holding, LLC, NN Houston Sub, Inc., Texas Genco Holdings, Inc. ("Texas
Genco"), HPC Merger Sub, Inc. and GC Power Acquisition LLC
|
CenterPoint
Energy’s Form 8-K dated July 21, 2004
|
1-31447
|
10.1
|
|||
|
3(a)
|
-
|
Restated
Articles of Incorporation of CenterPoint Energy
|
CenterPoint
Energy’s Form 8-K dated July 24, 2008
|
1-31447
|
3.2
|
|||
|
3(b)
|
-
|
Amended
and Restated Bylaws of CenterPoint Energy
|
CenterPoint
Energy’s Form 8-K dated January 20, 2010
|
1-31447
|
3.1
|
|||
|
4(a)
|
-
|
Form
of CenterPoint Energy Stock Certificate
|
CenterPoint
Energy’s Registration Statement on Form S-4
|
333-69502
|
4.1
|
|||
|
4(b)
|
-
|
Rights
Agreement dated January 1, 2002, between CenterPoint Energy and
JPMorgan Chase Bank, as Rights Agent
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2001
|
1-31447
|
4.2
|
|||
|
4(c)
|
-
|
Contribution
and Registration Agreement dated December 18, 2001 among Reliant
Energy, CenterPoint Energy and the Northern Trust Company, trustee under
the Reliant Energy, Incorporated Master Retirement Trust
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2001
|
1-31447
|
4.3
|
|||
|
4(d)(1)
|
-
|
Mortgage
and Deed of Trust, dated November 1, 1944 between Houston Lighting
and Power Company ("HL&P") and Chase Bank of Texas, National
Association (formerly, South Texas Commercial National Bank of Houston),
as Trustee, as amended and supplemented by 20 Supplemental Indentures
thereto
|
HL&P’s
Form S-7 filed on August 25, 1977
|
2-59748
|
2(b)
|
|
4(d)(2)
|
-
|
Twenty-First
through Fiftieth Supplemental Indentures to
Exhibit 4(d)(1)
|
HL&P’s
Form 10-K for the year ended December 31, 1989
|
1-3187
|
4(a)(2)
|
|||
|
4(d)(3)
|
-
|
Fifty-First
Supplemental Indenture to Exhibit 4(d)(1) dated as of March 25,
1991
|
HL&P’s
Form 10-Q for the quarter ended June 30, 1991
|
1-3187
|
4(a)
|
|||
|
4(d)(4)
|
-
|
Fifty-Second
through Fifty-Fifth Supplemental Indentures to Exhibit 4(d)(1) each
dated as of March 1, 1992
|
HL&P’s
Form 10-Q for the quarter ended March 31, 1992
|
1-3187
|
4
|
|||
|
4(d)(5)
|
-
|
Fifty-Sixth
and Fifty-Seventh Supplemental Indentures to Exhibit 4(d)(1) each
dated as of October 1, 1992
|
HL&P’s
Form 10-Q for the quarter ended September 30,
1992
|
1-3187
|
4
|
|||
|
4(d)(6)
|
-
|
Fifty-Eighth
and Fifty-Ninth Supplemental Indentures to Exhibit 4(d)(1) each dated
as of March 1, 1993
|
HL&P’s
Form 10-Q for the quarter ended March 31, 1993
|
1-3187
|
4
|
|||
|
4(d)(7)
|
-
|
Sixtieth
Supplemental Indenture to Exhibit 4(d)(1) dated as of July 1,
1993
|
HL&P’s
Form 10-Q for the quarter ended June 30, 1993
|
1-3187
|
4
|
|||
|
4(d)(8)
|
-
|
Sixty-First
through Sixty-Third Supplemental Indentures to Exhibit 4(d)(1) each
dated as of December 1, 1993
|
HL&P’s
Form 10-K for the year ended December 31, 1993
|
1-3187
|
4(a)(8)
|
|||
|
4(d)(9)
|
-
|
Sixty-Fourth
and Sixty-Fifth Supplemental Indentures to Exhibit 4(d)(1) each dated
as of July 1, 1995
|
HL&P’s
Form 10-K for the year ended December 31, 1995
|
1-3187
|
4(a)(9)
|
|||
|
4(e)(1)
|
-
|
General
Mortgage Indenture, dated as of October 10, 2002, between CenterPoint
Energy Houston Electric, LLC and JPMorgan Chase Bank, as
Trustee
|
CenterPoint
Houston’s Form 10-Q for the quarter ended September 30,
2002
|
1-3187
|
4(j)(1)
|
|||
|
4(e)(2)
|
-
|
Second
Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10,
2002
|
CenterPoint
Houston’s Form 10- Q for the quarter ended September 30,
2002
|
1-3187
|
4(j)(3)
|
|||
|
4(e)(3)
|
-
|
Third
Supplemental Indenture to Exhibit 4(e)(1), dated as of
October 10, 2002
|
CenterPoint
Houston’s Form 10-Q for the quarter ended September 30,
2002
|
1-3187
|
4(j)(4)
|
|||
|
4(e)(4)
|
-
|
Fourth
Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10,
2002
|
CenterPoint
Houston’s Form 10- Q for the quarter ended September 30,
2002
|
1-3187
|
4(j)(5)
|
|||
|
4(e)(5)
|
-
|
Fifth
Supplemental Indenture to Exhibit 4(e)(1), dated as of
October 10, 2002
|
CenterPoint
Houston’s Form 10-Q for the quarter ended September 30,
2002
|
1-3187
|
4(j)(6)
|
|||
|
4(e)(6)
|
-
|
Sixth
Supplemental Indenture to Exhibit 4(e)(1), dated as of
October 10, 2002
|
CenterPoint
Houston’s Form 10-Q for the quarter ended September 30,
2002
|
1-3187
|
4(j)(7)
|
|
4(e)(7)
|
-
|
Seventh
Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10,
2002
|
CenterPoint
Houston’s Form 10-Q for the quarter ended September 30,
2002
|
1-3187
|
4(j)(8)
|
|||
|
4(e)(8)
|
-
|
Eighth
Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10,
2002
|
CenterPoint
Houston’s Form 10-Q for the quarter ended September 30,
2002
|
1-3187
|
4(j)(9)
|
|||
|
4(e)(9)
|
-
|
Officer’s
Certificates dated October 10, 2002 setting forth the form, terms and
provisions of the First through Eighth Series of General Mortgage
Bonds
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2003
|
1-31447
|
4(e)(10)
|
|||
|
4(e)(10)
|
-
|
Ninth
Supplemental Indenture to Exhibit 4(e)(1), dated as of
November 12, 2002
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2002
|
1-31447
|
4(e)(10)
|
|||
|
4(e)(11)
|
-
|
Officer’s
Certificate dated November 12, 2003 setting forth the form, terms and
provisions of the Ninth Series of General Mortgage Bonds
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2003
|
1-31447
|
4(e)(12)
|
|||
|
4(e)(12)
|
-
|
Tenth
Supplemental Indenture to Exhibit 4(e)(1), dated as of March 18,
2003
|
CenterPoint
Energy’s Form 8-K dated March 13, 2003
|
1-31447
|
4.1
|
|||
|
4(e)(13)
|
-
|
Officer’s
Certificate dated March 18, 2003 setting forth the form, terms and
provisions of the Tenth Series and Eleventh Series of General Mortgage
Bonds
|
CenterPoint
Energy’s Form 8-K dated March 13, 2003
|
1-31447
|
4.2
|
|||
|
4(e)(14)
|
-
|
Eleventh
Supplemental Indenture to Exhibit 4(e)(1), dated as of May 23,
2003
|
CenterPoint
Energy’s Form 8-K dated May 16, 2003
|
1-31447
|
4.2
|
|||
|
4(e)(15)
|
-
|
Officer’s
Certificate dated May 23, 2003 setting forth the form, terms and
provisions of the Twelfth Series of General Mortgage Bonds
|
CenterPoint
Energy’s Form 8-K dated May 16, 2003
|
1-31447
|
4.1
|
|||
|
4(e)(16)
|
-
|
Twelfth
Supplemental Indenture to Exhibit 4(e)(1), dated as of September 9,
2003
|
CenterPoint
Energy’s Form 8-K dated September 9, 2003
|
1-31447
|
4.2
|
|||
|
4(e)(17)
|
-
|
Officer’s
Certificate dated September 9, 2003 setting forth the form, terms and
provisions of the Thirteenth Series of General Mortgage Bonds
|
CenterPoint
Energy’s Form 8-K dated September 9, 2003
|
1-31447
|
4.3
|
|||
|
4(e)(18)
|
-
|
Thirteenth
Supplemental Indenture to Exhibit 4(e)(1), dated as of February 6,
2004
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(e)(16)
|
|||
|
4(e)(19)
|
-
|
Officer’s
Certificate dated February 6, 2004 setting forth the form, terms and
provisions of the Fourteenth Series of General Mortgage Bonds
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(e)(17)
|
|
4(e)(20)
|
-
|
Fourteenth
Supplemental Indenture to Exhibit 4(e)(1), dated as of February 11,
2004
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(e)(18)
|
|||
|
4(e)(21)
|
-
|
Officer’s
Certificate dated February 11, 2004 setting forth the form, terms and
provisions of the Fifteenth Series of General Mortgage Bonds
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(e)(19)
|
|||
|
4(e)(22)
|
-
|
Fifteenth
Supplemental Indenture to Exhibit 4(e)(1), dated as of March 31,
2004
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(e)(20)
|
|||
|
4(e)(23)
|
-
|
Officer’s
Certificate dated March 31, 2004 setting forth the form, terms and
provisions of the Sixteenth Series of General Mortgage Bonds
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(e)(21)
|
|||
|
4(e)(24)
|
-
|
Sixteenth
Supplemental Indenture to Exhibit 4(e)(1), dated as of March 31,
2004
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(e)(22)
|
|||
|
4(e)(25)
|
-
|
Officer’s
Certificate dated March 31, 2004 setting forth the form, terms and
provisions of the Seventeenth Series of General Mortgage
Bonds
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(e)(23)
|
|||
|
4(e)(26)
|
-
|
Seventeenth
Supplemental Indenture to Exhibit 4(e)(1), dated as of March 31,
2004
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(e)(24)
|
|||
|
4(e)(27)
|
-
|
Officer’s
Certificate dated March 31, 2004 setting forth the form, terms and
provisions of the Eighteenth Series of General Mortgage Bonds
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(e)(25)
|
|||
|
4(e)(28)
|
-
|
Nineteenth
Supplemental Indenture to Exhibit 4(e)(1), dated as of November 26,
2008
|
CenterPoint
Energy’s Form 8-K dated November 25, 2008
|
1-31447
|
4.2
|
|||
|
4(e)(29)
|
-
|
Officer’s
Certificate date November 26, 2008 setting forth the form, terms and
provisions of the Twentieth Series of General Mortgage Bonds
|
CenterPoint
Energy’s Form 8-K dated November 25, 2008
|
1-31447
|
4.3
|
|||
|
4(e)(30)
|
-
|
Twentieth
Supplemental Indenture to Exhibit 4(e)(1), dated as of December 9,
2008
|
CenterPoint
Houston’s Form 8-K dated January 6, 2009
|
1-3187
|
4.2
|
|||
|
4(e)(31)
|
-
|
Twenty-First
Supplemental Indenture to Exhibit 4(e)(1), dated as of January 9,
2009
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
4(e)(31)
|
|||
|
4(e)(32)
|
-
|
Officer’s
Certificate date January 20, 2009 setting forth the form, terms and
provisions of the Twenty-First Series of General Mortgage
Bonds
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
4(e)(32)
|
|
4(f)(1)
|
-
|
Indenture,
dated as of February 1, 1998, between Reliant Energy Resources Corp.
("RERC Corp.") and Chase Bank of Texas, National Association, as
Trustee
|
CERC
Corp.’s Form 8-K dated February 5, 1998
|
1-13265
|
4.1
|
|||
|
4(f)(2)
|
-
|
Supplemental
Indenture No. 1 to Exhibit 4(f)(1), dated as of February 1,
1998, providing for the issuance of RERC Corp.’s 6 1/2% Debentures
due February 1, 2008
|
CERC
Corp.’s Form 8-K dated November 9, 1998
|
1-13265
|
4.2
|
|||
|
4(f)(3)
|
-
|
Supplemental
Indenture No. 2 to Exhibit 4(f)(1), dated as of November 1,
1998, providing for the issuance of RERC Corp.’s 6 3/8% Term Enhanced
ReMarketable Securities
|
CERC
Corp.’s Form 8-K dated November 9, 1998
|
1-13265
|
4.1
|
|||
|
4(f)(4)
|
-
|
Supplemental
Indenture No. 3 to Exhibit 4(f)(1), dated as of July 1,
2000, providing for the issuance of RERC Corp.’s 8.125% Notes due
2005
|
CERC
Corp.’s Registration Statement on Form S-4
|
333-49162
|
4.2
|
|||
|
4(f)(5)
|
-
|
Supplemental
Indenture No. 4 to Exhibit 4(f)(1), dated as of
February 15, 2001, providing for the issuance of RERC Corp.’s
7.75% Notes due 2011
|
CERC
Corp.’s Form 8-K dated February 21, 2001
|
1-13265
|
4.1
|
|||
|
4(f)(6)
|
-
|
Supplemental
Indenture No. 5 to Exhibit 4(f)(1), dated as of March 25,
2003, providing for the issuance of CenterPoint Energy Resources Corp.’s
("CERC Corp.’s") 7.875% Senior Notes due 2013
|
CenterPoint
Energy’s Form 8-K dated March 18, 2003
|
1-31447
|
4.1
|
|||
|
4(f)(7)
|
-
|
Supplemental
Indenture No. 6 to Exhibit 4(f)(1), dated as of April 14,
2003, providing for the issuance of CERC Corp.’s 7.875% Senior Notes
due 2013
|
CenterPoint
Energy’s Form 8-K dated April 7, 2003
|
1-31447
|
4.2
|
|||
|
4(f)(8)
|
-
|
Supplemental
Indenture No. 7 to Exhibit 4(f)(1), dated as of November 3,
2003, providing for the issuance of CERC Corp.’s 5.95% Senior Notes
due 2014
|
CenterPoint
Energy’s Form 8-K dated October 29, 2003
|
1-31447
|
4.2
|
|||
|
4(f)(9)
|
-
|
Supplemental
Indenture No. 8 to Exhibit 4(f)(1), dated as of
December 28, 2005, providing for a modification of CERC Corp.’s 6
1/2% Debentures due 2008
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(f)(9)
|
|||
|
4(f)(10)
|
-
|
Supplemental
Indenture No. 9 to Exhibit 4(f)(1), dated as of May 18,
2006, providing for the issuance of CERC Corp.’s 6.15% Senior Notes
due 2016
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30,
2006
|
1-31447
|
4.7
|
|
4(f)(11)
|
-
|
Supplemental
Indenture No. 10 to Exhibit 4(f)(1), dated as of
February 6, 2007, providing for the issuance of CERC Corp.’s
6.25% Senior Notes due 2037
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2006
|
1-31447
|
4(f)(11)
|
|||
|
4(f)(12)
|
-
|
Supplemental
Indenture No. 11 to Exhibit 4(f)(1) dated as of October 23, 2007,
providing for the issuance of CERC Corp.’s 6.125% Senior Notes due
2017
|
CenterPoint
Energy’s Form 10-Q for the quarter ended September 30,
2007
|
1-31447
|
4.8
|
|||
|
4(f)(13)
|
-
|
Supplemental
Indenture No. 12 to Exhibit 4(f)(1) dated as of October 23, 2007,
providing for the issuance of CERC Corp.’s 6.625% Senior Notes due
2037
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30, 2008
|
1-31447
|
4.9
|
|||
|
4(f)(14)
|
-
|
Supplemental
Indenture No. 13 to Exhibit 4(f)(1) dated as of May 15, 2008, providing
for the issuance of CERC Corp.’s 6.00% Senior Notes due 2018
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30,
2008
|
1-31447
|
4.9
|
|||
|
4(g)(1)
|
-
|
Indenture,
dated as of May 19, 2003, between CenterPoint Energy and JPMorgan
Chase Bank, as Trustee
|
CenterPoint
Energy’s Form 8-K dated May 19, 2003
|
1-31447
|
4.1
|
|||
|
4(g)(2)
|
-
|
Supplemental
Indenture No. 1 to Exhibit 4(g)(1), dated as of May 19,
2003, providing for the issuance of CenterPoint Energy’s 3.75% Convertible
Senior Notes due 2023
|
CenterPoint
Energy’s Form 8-K dated May 19, 2003
|
1-31447
|
4.2
|
|||
|
4(g)(3)
|
-
|
Supplemental
Indenture No. 2 to Exhibit 4(g)(1), dated as of May 27,
2003, providing for the issuance of CenterPoint Energy’s
5.875% Senior Notes due 2008 and 6.85% Senior Notes due
2015
|
CenterPoint
Energy’s Form 8-K dated May 19, 2003
|
1-31447
|
4.3
|
|||
|
4(g)(4)
|
-
|
Supplemental
Indenture No. 3 to Exhibit 4(g)(1), dated as of
September 9, 2003, providing for the issuance of CenterPoint Energy’s
7.25% Senior Notes due 2010
|
CenterPoint
Energy’s Form 8-K dated September 9, 2003
|
1-31447
|
4.2
|
|||
|
4(g)(5)
|
-
|
Supplemental
Indenture No. 4 to Exhibit 4(g)(1), dated as of
December 17, 2003, providing for the issuance of CenterPoint Energy’s
2.875% Convertible Senior Notes due 2024
|
CenterPoint
Energy’s Form 8-K dated December 10, 2003
|
1-31447
|
4.2
|
|||
|
4(g)(6)
|
-
|
Supplemental
Indenture No. 5 to Exhibit 4(g)(1), dated as of
December 13, 2004, as supplemented by Exhibit 4(g)(5), relating
to the issuance of CenterPoint Energy’s 2.875% Convertible Senior
Notes due 2024
|
CenterPoint
Energy’s Form 8-K dated December 9, 2004
|
1-31447
|
4.1
|
|
4(g)(7)
|
-
|
Supplemental
Indenture No. 6 to Exhibit 4(g)(1), dated as of August 23,
2005, providing for the issuance of CenterPoint Energy’s 3.75% Convertible
Senior Notes, Series B due 2023
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(g)(7)
|
|||
|
4(g)(8)
|
-
|
Supplemental
Indenture No. 7 to Exhibit 4(g)(1), dated as of February 6,
2007, providing for the issuance of CenterPoint Energy’s 5.95% Senior
Notes due 2017
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2006
|
1-31447
|
4(g)(8)
|
|||
|
4(g)(9)
|
-
|
Supplemental
Indenture No. 8 to Exhibit 4(g)(1), dated as of May 5,
2008, providing for the issuance of CenterPoint Energy’s 6.50% Senior
Notes due 2018
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30,
2008
|
1-31447
|
4.7
|
|||
|
4(h)(1)
|
-
|
Subordinated
Indenture dated as of September 1, 1999
|
Reliant
Energy’s Form 8-K dated September 1, 1999
|
1-3187
|
4.1
|
|||
|
4(h)(2)
|
-
|
Supplemental
Indenture No. 1 dated as of September 1, 1999, between Reliant
Energy and Chase Bank of Texas (supplementing Exhibit 4(h)(1) and
providing for the issuance Reliant Energy’s 2% Zero-Premium Exchangeable
Subordinated Notes Due 2029)
|
Reliant
Energy’s Form 8-K dated September 15, 1999
|
1-3187
|
4.2
|
|||
|
4(h)(3)
|
-
|
Supplemental
Indenture No. 2 dated as of August 31, 2002, between CenterPoint
Energy, Reliant Energy and JPMorgan Chase Bank (supplementing
Exhibit 4(h)(1))
|
CenterPoint
Energy’s Form 8-K12B dated August 31, 2002
|
1-31447
|
4(e)
|
|||
|
4(h)(4)
|
-
|
Supplemental
Indenture No. 3 dated as of December 28, 2005, between
CenterPoint Energy, Reliant Energy and JPMorgan Chase Bank (supplementing
Exhibit 4(h)(1))
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2005
|
1-31447
|
4(h)(4)
|
|||
|
4(i)(1)
|
-
|
$1,200,000,000
Second Amended and Restated Credit Agreement dated as of June 29, 2007,
among CenterPoint Energy, as Borrower, and the banks named
therein
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30, 2007
|
1-31447
|
4.3
|
|||
|
4(i)(2)
|
-
|
First
Amendment to Exhibit 4(i)(1), dated as of August 20, 2008, among
CenterPoint Energy, as Borrower, and the banks named therein
|
CenterPoint
Energy’s Form 10-Q for the quarter ended September 30,
2008
|
1-31447
|
4.4
|
|||
|
4(i)(3)
|
-
|
Second
Amendment to Exhibit 4(i)(1), dated as of November 18, 2008, among
CenterPoint Energy, as Borrower, and the banks named therein
|
CenterPoint
Energy’s Form 8-K dated November 18, 2008
|
1-31447
|
4.1
|
|
4(i)(4)
|
-
|
Third
Amendment to Exhibit 4(i)(1), dated as of February 5, 2010, among
CenterPoint Energy, as Borrower, and the banks named therein
|
CenterPoint
Energy’s Form 8-K dated February 5, 2010
|
1-31447
|
4.1
|
|||
|
4(j)(1)
|
-
|
$300,000,000
Second Amended and Restated Credit Agreement dated as of June 29, 2007,
among CenterPoint Houston, as Borrower, and the banks named
therein
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30, 2007
|
1-31447
|
4.4
|
|||
|
4(j)(2)
|
-
|
First
Amendment to Exhibit 4(j)(1), dated as of November 18, 2008, among
CenterPoint Houston, as Borrower, and the banks named therein
|
CenterPoint
Energy’s Form 8-K dated November 18, 2008
|
1-31447
|
4.2
|
|||
|
4(k)
|
-
|
$950,000,000
Second Amended and Restated Credit Agreement dated as of June 29, 2007,
among CERC Corp., as Borrower, and the banks named therein
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30, 2007
|
1-31447
|
4.5
|
|||
|
4(l)
|
-
|
$600,000,000
Credit Agreement dated as of November 25, 2008, among CenterPoint
Houston, as Borrower, and the banks named therein
|
CenterPoint
Energy’s Form 8-K dated November 25, 2008
|
1-31447
|
4.1
|
Pursuant
to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy has
not filed as exhibits to this Form 10-K certain long-term debt instruments,
including indentures, under which the total amount of securities authorized does
not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on
a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any
such instrument to the SEC upon request.
|
Exhibit
Number
|
Description
|
Report
or Registration Statement
|
SEC
File or
Registration
Number
|
Exhibit
Reference
|
||||
|
*10(a)
|
-
|
CenterPoint
Energy Executive Benefits Plan, as amended and restated effective
June 18, 2003
|
CenterPoint
Energy’s Form 10-Q for the quarter ended September 30,
2003
|
1-31447
|
10.4
|
|||
|
*10(b)(1)
|
-
|
Executive
Incentive Compensation Plan of Houston Industries Incorporated ("HI")
effective as of January 1, 1982
|
HI’s
Form 10-K for the year ended December 31, 1991
|
1-7629
|
10(b)
|
|||
|
*10(b)(2)
|
-
|
First
Amendment to Exhibit 10(b)(1) effective as of March 30,
1992
|
HI’s
Form 10-Q for the quarter ended March 31, 1992
|
1-7629
|
10(a)
|
|||
|
*10(b)(3)
|
-
|
Second
Amendment to Exhibit 10(b)(1) effective as of November 4,
1992
|
HI’s
Form 10-K for the year ended December 31, 1992
|
1-7629
|
10(b)
|
|||
|
*10(b)(4)
|
-
|
Third
Amendment to Exhibit 10(b)(1) effective as of September 7,
1994
|
HI’s
Form 10-K for the year ended December 31, 1994
|
1-7629
|
10(b)(4)
|
|||
|
*10(b)(5)
|
-
|
Fourth
Amendment to Exhibit 10(b)(1) effective as of August 6,
1997
|
HI’s
Form 10-K for the year ended December 31, 1997
|
1-3187
|
10(b)(5)
|
|
*10(c)(1)
|
-
|
Executive
Incentive Compensation Plan of HI as amended and restated on
January 1, 1991
|
HI’s
Form 10-K for the year ended December 31, 1990
|
1-7629
|
10(b)
|
|||
|
*10(c)(2)
|
-
|
First
Amendment to Exhibit 10(c)(1) effective as of January 1,
1991
|
HI’s
Form 10-K for the year ended December 31, 1991
|
1-7629
|
10(f)(2)
|
|||
|
*10(c)(3)
|
-
|
Second
Amendment to Exhibit 10(c)(1) effective as of March 30,
1992
|
HI’s
Form 10-Q for the quarter ended March 31, 1992
|
1-7629
|
10(d)
|
|||
|
*10(c)(4)
|
-
|
Third
Amendment to Exhibit 10(c)(1) effective as of November 4,
1992
|
HI’s
Form 10-K for the year ended December 31, 1992
|
1-7629
|
10(f)(4)
|
|||
|
*10(c)(5)
|
-
|
Fourth
Amendment to Exhibit 10(c)(1) effective as of January 1,
1993
|
HI’s
Form 10-K for the year ended December 31, 1992
|
1-7629
|
10(f)(5)
|
|||
|
*10(c)(6)
|
-
|
Fifth
Amendment to Exhibit 10(c)(1) effective in part, January 1,
1995, and in part, September 7, 1994
|
HI’s
Form 10-K for the year ended December 31, 1994
|
1-7629
|
10(f)(6)
|
|||
|
*10(c)(7)
|
-
|
Sixth
Amendment to Exhibit 10(c)(1) effective as of August 1,
1995
|
HI’s
Form 10-Q for the quarter ended June 30, 1995
|
1-7629
|
10(a)
|
|||
|
*10(c)(8)
|
-
|
Seventh
Amendment to Exhibit 10(c)(1) effective as of January 1,
1996
|
HI’s
Form 10-Q for the quarter ended June 30, 1996
|
1-7629
|
10(a)
|
|||
|
*10(c)(9)
|
-
|
Eighth
Amendment to Exhibit 10(c)(1) effective as of January 1,
1997
|
HI’s
Form 10-Q for the quarter ended June 30, 1997
|
1-7629
|
10(a)
|
|||
|
*10(c)(10)
|
-
|
Ninth
Amendment to Exhibit 10(c)(1) effective in part, January 1,
1997, and in part, January 1, 1998
|
HI’s
Form 10-K for the year ended December 31, 1997
|
1-3187
|
10(f)(10)
|
|||
|
*10(d)
|
-
|
Benefit
Restoration Plan of HI effective as of June 1, 1985
|
HI’s
Form 10-Q for the quarter ended March 31, 1987
|
1-7629
|
10(c)
|
|||
|
*10(e)
|
-
|
Benefit
Restoration Plan of HI as amended and restated effective as of
January 1, 1988
|
HI’s
Form 10-K for the year ended December 31, 1991
|
1-7629
|
10(g)(2)
|
|||
|
*10(f)(1)
|
-
|
Benefit
Restoration Plan of HI, as amended and restated effective as of
July 1, 1991
|
HI’s
Form 10-K for the year ended December 31, 1991
|
1-7629
|
10(g)(3)
|
|||
|
*10(f)(2)
|
-
|
First
Amendment to Exhibit 10(f)(1) effective in part, August 6, 1997,
in part, September 3, 1997, and in part, October 1,
1997
|
HI’s
Form 10-K for the year ended December 31, 1997
|
1-3187
|
10(i)(2)
|
|
*10(f)(3)
|
-
|
Third
Amendment to Exhibit 10(f)(1) effective as of January 1,
2008
|
CenterPoint
Energy’s Form 8-K dated December 22, 2008
|
1-31447
|
10.2
|
|||
|
*10(g)
|
-
|
CenterPoint
Energy Benefit Restoration Plan, effective as of January 1,
2008
|
CenterPoint
Energy’s Form 8-K dated December 22, 2008
|
1-31447
|
10.1
|
|||
|
*10(h)(1)
|
-
|
HI
1995 Section 415 Benefit Restoration Plan effective August 1,
1995
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
10(h)(1)
|
|||
|
*10(h)(2)
|
-
|
First
Amendment to Exhibit 10(h)(1) effective as of August 1,
1995
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
10(h)(2)
|
|||
|
*10(i)
|
-
|
CenterPoint
Energy 1985 Deferred Compensation Plan, as amended and restated effective
January 1, 2003
|
CenterPoint
Energy’s Form 10-Q for the quarter ended September 30,
2003
|
1-31447
|
10.1
|
|||
|
*10(j)(1)
|
-
|
Reliant
Energy 1994 Long- Term Incentive Compensation Plan, as amended and
restated effective January 1, 2001
|
Reliant
Energy’s Form 10-Q for the quarter ended June 30,
2002
|
1-3187
|
10.6
|
|||
|
*10(j)(2)
|
-
|
First
Amendment to Exhibit 10(j)(1), effective December 1,
2003
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2003
|
1-31447
|
10(p)(7)
|
|||
|
*10(j)(3)
|
-
|
Form
of Non-Qualified Stock Option Award Notice under
Exhibit 10(i)(1)
|
CenterPoint
Energy’s Form 8-K dated January 25, 2005
|
1-31447
|
10.6
|
|||
|
*10(k)(1)
|
-
|
Savings
Restoration Plan of HI effective as of January 1,
1991
|
HI’s
Form 10-K for the year ended December 31, 1990
|
1-7629
|
10(f)
|
|||
|
*10(k)(2)
|
-
|
First
Amendment to Exhibit 10(k)(1) effective as of January 1,
1992
|
HI’s
Form 10-K for the year ended December 31, 1991
|
1-7629
|
10(l)(2)
|
|||
|
*10(k)(3)
|
-
|
Second
Amendment to Exhibit 10(k)(1) effective in part, August 6, 1997,
and in part, October 1, 1997
|
HI’s
Form 10-K for the year ended December 31, 1997
|
1-3187
|
10(q)(3)
|
|||
|
*10(l)(3)
|
-
|
Amended
and Restated CenterPoint Energy, Inc. 1991 Savings Restoration Plan,
effective as of January 1, 2008
|
CenterPoint
Energy’s Form 8-K dated December 22, 2008
|
1-31447
|
10.4
|
|||
|
*10(m)
|
-
|
CenterPoint
Energy Savings Restoration Plan, effective as of January 1,
2008
|
CenterPoint
Energy’s Form 8-K dated December 22, 2008
|
1-31447
|
10.3
|
|||
|
*10(n)(1)
|
-
|
CenterPoint
Energy Outside Director Benefits Plan, as amended and restated effective
June 18, 2003
|
CenterPoint
Energy’s Form 10-Q for the quarter ended September 30,
2003
|
1-31447
|
10.6
|
|
*10(n)(2)
|
-
|
First
Amendment to Exhibit 10(n)(1) effective as of January 1,
2004
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30,
2004
|
1-31447
|
10.6
|
|||
|
*10(n)(3)
|
-
|
CenterPoint
Energy Outside Director Benefits Plan, as amended and restated effective
December 31, 2008
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
10(n)(3)
|
|||
|
*10(o)
|
-
|
CenterPoint
Energy Executive Life Insurance Plan, as amended and restated effective
June 18, 2003
|
CenterPoint
Energy’s Form 10-Q for the quarter ended September 30,
2003
|
1-31447
|
10.5
|
|||
|
*10(p)
|
-
|
Employment
and Supplemental Benefits Agreement between HL&P and Hugh Rice
Kelly
|
HI’s
Form 10-Q for the quarter ended March 31, 1987
|
1-7629
|
10(f)
|
|||
|
10(q)(1)
|
-
|
Stockholder’s
Agreement dated as of July 6, 1995 between Houston Industries
Incorporated and Time Warner Inc.
|
Schedule
13-D dated July 6, 1995
|
5-19351
|
2
|
|||
|
10(q)(2)
|
-
|
Amendment
to Exhibit 10(q)(1) dated November 18, 1996
|
HI’s
Form 10-K for the year ended December 31, 1996
|
1-7629
|
10(x)(4)
|
|||
|
*10(r)(1)
|
-
|
Houston
Industries Incorporated Executive Deferred Compensation Trust effective as
of December 19, 1995
|
HI’s
Form 10-K for the year ended December 31, 1995
|
1-7629
|
10(7)
|
|||
|
*10(r)(2)
|
-
|
First
Amendment to Exhibit 10(r)(1) effective as of August 6,
1997
|
HI’s
Form 10-Q for the quarter ended June 30, 1998
|
1-3187
|
10
|
|||
|
*10(s)
|
-
|
Letter
Agreement dated May 24, 2007 between CenterPoint Energy and Milton
Carroll, Non-Executive Chairman of the Board of Directors of CenterPoint
Energy
|
CenterPoint
Energy’s Form 8-K dated May 31, 2007
|
1-31447
|
10.1
|
|||
|
*10(t)
|
-
|
Reliant
Energy, Incorporated and Subsidiaries Common Stock Participation Plan for
Designated New Employees and Non-Officer Employees, as amended and
restated effective January 1, 2001
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2002
|
1-31447
|
10(y)(2)
|
|||
|
*10(u)(1)
|
-
|
Long-Term
Incentive Plan of CenterPoint Energy, Inc. (amended and restated effective
as of May 1, 2004)
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30,
2004
|
1-31447
|
10.5
|
|||
|
*10(u)(2)
|
-
|
First
Amendment to Exhibit (u)(1), effective January 1, 2007
|
CenterPoint
Energy’s Form 10-Q for the quarter ended March 31, 2007
|
1-31447
|
10.5
|
|||
|
*10(u)(3)
|
-
|
Form
of Non-Qualified Stock Option Award Agreement under
Exhibit 10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated January 25, 2005
|
1-31447
|
10.1
|
|
*10(u)(4)
|
-
|
Form
of Restricted Stock Award Agreement under Exhibit 10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated January 25, 2005
|
1-31447
|
10.2
|
|||
|
*10(u)(5)
|
-
|
Form
of Performance Share Award under Exhibit 10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated January 25, 2005
|
1-31447
|
10.3
|
|||
|
*10(u)(6)
|
-
|
Form
of Performance Share Award Agreement for 20XX-20XX Performance Cycle under
Exhibit 10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated February 22, 2006
|
1-31447
|
10.2
|
|||
|
*10(u)(7)
|
-
|
Form
of Restricted Stock Award Agreement (With Performance Vesting Requirement)
under Exhibit 10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated February 21, 2005
|
1-31447
|
10.2
|
|||
|
*10(u)(8)
|
-
|
Form
of Stock Award Agreement (With Performance Goal) under Exhibit
10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated February 22, 2006
|
1-31447
|
10.3
|
|||
|
*10(u)(9)
|
-
|
Form
of Performance Share Award Agreement for 20XX - 20XX Performance Cycle
under Exhibit 10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated February 21, 2007
|
1-31447
|
10.1
|
|||
|
*10(u)(10)
|
-
|
Form
of Stock Award Agreement (With Performance Goal) under
Exhibit 10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated February 21, 2007
|
1-31447
|
10.2
|
|||
|
*10(u)(11)
|
-
|
Form
of Stock Award Agreement (Without Performance Goal) under Exhibit
10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated February 21, 2007
|
1-31447
|
10.3
|
|||
|
*10(u)(12)
|
-
|
Form
of Performance Share Award Agreement for 20XX - 20XX Performance Cycle
under Exhibit 10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated February 20, 2008
|
1-31447
|
10.1
|
|||
|
*10(u)(13)
|
-
|
Form
of Stock Award Agreement (With Performance Goal) under
Exhibit 10(u)(1)
|
CenterPoint
Energy’s Form 8-K dated February 20, 2008
|
1-31447
|
10.2
|
|||
|
10(v)(1)
|
-
|
Master
Separation Agreement entered into as of December 31, 2000 between
Reliant Energy, Incorporated and Reliant Resources,
Inc.
|
Reliant
Energy’s Form 10-Q for the quarter ended March 31,
2001
|
1-3187
|
10.1
|
|||
|
10(v)(2)
|
-
|
First
Amendment to Exhibit 10(v)(1) effective as of February 1,
2003
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2002
|
1-31447
|
10(bb)(5)
|
|||
|
10(v)(3)
|
-
|
Employee
Matters Agreement, entered into as of December 31, 2000, between
Reliant Energy, Incorporated and Reliant Resources,
Inc.
|
Reliant
Energy’s Form 10-Q for the quarter ended March 31,
2001
|
1-3187
|
10.5
|
|
10(v)(4)
|
-
|
Retail
Agreement, entered into as of December 31, 2000, between Reliant
Energy, Incorporated and Reliant Resources, Inc.
|
Reliant
Energy’s Form 10-Q for the quarter ended March 31,
2001
|
1-3187
|
10.6
|
|||
|
10(v)(5)
|
-
|
Tax
Allocation Agreement, entered into as of December 31, 2000, between
Reliant Energy, Incorporated and Reliant Resources,
Inc.
|
Reliant
Energy’s Form 10-Q for the quarter ended March 31,
2001
|
1-3187
|
10.8
|
|||
|
10(w)(1)
|
-
|
Separation
Agreement entered into as of August 31, 2002 between CenterPoint
Energy and Texas Genco
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2002
|
1-31447
|
10(cc)(1)
|
|||
|
10(w)(2)
|
-
|
Transition
Services Agreement, dated as of August 31, 2002, between CenterPoint
Energy and Texas Genco
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2002
|
1-31447
|
10(cc)(2)
|
|||
|
10(w)(3)
|
-
|
Tax
Allocation Agreement, dated as of August 31, 2002, between
CenterPoint Energy and Texas Genco
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2002
|
1-31447
|
10(cc)(3)
|
|||
|
*10(x)
|
-
|
Retention
Agreement effective October 15, 2001 between Reliant Energy and David
G. Tees
|
Reliant
Energy’s Form 10-K for the year ended December 31,
2001
|
1-3187
|
10(jj)
|
|||
|
*10(y)
|
-
|
Retention
Agreement effective October 15, 2001 between Reliant Energy and
Michael A. Reed
|
Reliant
Energy’s Form 10-K for the year ended December 31,
2001
|
1-3187
|
10(kk)
|
|||
|
*10(z)
|
-
|
Non-Qualified
Unfunded Executive Supplemental Income Retirement Plan of Arkla, Inc.
effective as of August 1, 1983
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2002
|
1-31447
|
10(gg)
|
|||
|
*10(aa)(1)
|
-
|
Deferred
Compensation Plan for Directors of Arkla, Inc. effective as of
November 10, 1988
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2002
|
1-31447
|
10(hh)(1)
|
|||
|
*10(aa)(2)
|
-
|
First
Amendment to Exhibit 10(aa)(1) effective as of August 6,
1997
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2002
|
1-31447
|
10(hh)(2)
|
|||
|
*10(bb)(1)
|
-
|
CenterPoint
Energy, Inc. Deferred Compensation Plan, as amended and restated effective
January 1, 2003
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30,
2003
|
1-31447
|
10.2
|
|||
|
*10(bb)(2)
|
-
|
First
Amendment to Exhibit 10(bb)(1) effective as of January 1,
2008
|
CenterPoint
Energy’s Form 8-K dated February 20, 2008
|
1-31447
|
10.4
|
|||
|
*10(bb)(3)
|
-
|
CenterPoint
Energy 2005 Deferred Compensation Plan, effective January 1,
2008
|
CenterPoint
Energy’s Form 8-K dated February 20, 2008
|
1-31447
|
10.3
|
|
*10(bb)(4)
|
-
|
Amended
and Restated CenterPoint Energy 2005 Deferred Compensation Plan, effective
January 1, 2009
|
CenterPoint
Energy’s Form 10-Q for the quarter ended September 30,
2008
|
1-31447
|
10.1
|
|||
|
*10(cc)(1)
|
-
|
CenterPoint
Energy Short Term Incentive Plan, as amended and restated effective
January 1, 2003
|
CenterPoint
Energy’s Form 10-Q for the quarter ended September 30,
2003
|
1-31447
|
10.3
|
|||
|
*10(cc)(2)
|
-
|
Second
Amendment to Exhibit 10(cc)(1)
|
CenterPoint
Energy’s Form 8-K dated December 10, 2009
|
1-31447
|
10.1
|
|||
|
*10(dd)
|
-
|
CenterPoint
Energy Stock Plan for Outside Directors, as amended and restated effective
May 7, 2003
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2003
|
1-31447
|
10(ll)
|
|||
|
10(ee)
|
-
|
City
of Houston Franchise Ordinance
|
CenterPoint
Energy’s Form 10-Q for the quarter ended June 30,
2005
|
1-31447
|
10.1
|
|||
|
10(ff)
|
-
|
Letter
Agreement dated March 16, 2006 between CenterPoint Energy and John T.
Cater
|
CenterPoint
Energy’s Form 10-Q for the quarter ended March 30,
2006
|
1-31447
|
10
|
|||
|
10(gg)(1)
|
-
|
Amended
and Restated HL&P Executive Incentive Compensation Plan effective as
of January 1, 1985
|
CenterPoint
Energy’s Form 10-Q for the quarter ended September 30,
2008
|
1-31447
|
10.2
|
|||
|
10(gg)(2)
|
-
|
First
Amendment to Exhibit 10(gg)(1) effective as of January 1,
2008
|
CenterPoint
Energy’s Form 10-Q for the quarter ended September 30,
2008
|
1-31447
|
10.3
|
|||
|
*10(hh)(1)
|
-
|
Executive
Benefits Agreement by and between HL&P and Thomas R. Standish
effective August 20, 1993
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
10(hh)(1)
|
|||
|
*10(hh)(2)
|
-
|
First
Amendment to Exhibit 10(hh)(1) effective as of December 31,
2008
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
10(hh)(2)
|
|||
|
*10(ii)(1)
|
-
|
Executive
Benefits Agreement by and between HL&P and David M. McClanahan
effective August 24, 1993
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
10(ii)(1)
|
|||
|
*10(ii)(2)
|
-
|
First
Amendment to Exhibit 10(ii)(1) effective as of December 31,
2008
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
10(ii)(2)
|
|||
|
*10(jj)(1)
|
-
|
Executive
Benefits Agreement by and between HL&P and Joseph B. McGoldrick
effective August 30, 1993
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
10(jj)(1)
|
|||
|
*10(jj)(2)
|
-
|
First
Amendment to Exhibit 10(jj)(1) effective as of December 31,
2008
|
CenterPoint
Energy’s Form 10-K for the year ended December 31,
2008
|
1-31447
|
10(jj)(2)
|
|
*10(kk)(1)
|
-
|
CenterPoint
Energy, Inc. 2009 Long Term Incentive Plan
|
CenterPoint
Energy’s Schedule 14A dated March 13, 2009
|
1-31447
|
A
|
|||
|
†*10(kk)(2)
|
-
|
|
||||||
|
†*10(kk)(3)
|
-
|
|
||||||
|
†10(ll)
|
-
|
|
||||||
|
†10(mm)
|
-
|
|
||||||
|
10(nn)
|
-
|
Form
of Executive Officer Change in Control Agreement
|
CenterPoint
Energy’s Form 10-K for the year ended December 31, 2008
|
1-31447
|
10(nn)
|
|||
|
10(oo)
|
-
|
Form
of Corporate Officer Change in Control Agreement
|
CenterPoint
Energy’s Form 10-K for the year ended December 31, 2008
|
1-31447
|
10(oo)
|
|||
|
†12
|
-
|
|
||||||
|
†21
|
-
|
|
||||||
|
†23
|
-
|
|
||||||
|
†31.1
|
-
|
|
||||||
|
†31.2
|
-
|
|
||||||
|
†32.1
|
-
|
|
||||||
|
†32.2
|
-
|
|
||||||
|
†101.INS
|
-
|
XBRL
Instance Document (1)
|
||||||
|
†101.SCH
|
-
|
XBRL
Taxonomy Extension Schema Document (1)
|
||||||
|
†101.CAL
|
-
|
XBRL
Taxonomy Extension Calculation Linkbase Document (1)
|
|
†101.DEF
|
- |
XBRL
Taxonomy Extension Definition Linkbase Document (1)
|
||||||
|
†101.LAB
|
-
|
XBRL
Taxonomy Extension Labels Linkbase Document (1)
|
||||||
|
†101.PRE
|
-
|
XBRL
Taxonomy Extension Presentation Linkbase Document (1)
|
(1) Furnished,
not filed.
140
Exhibit
10(kk)(2)
CENTERPOINT ENERGY, INC.
2009 LONG TERM INCENTIVE PLAN
QUALIFIED PERFORMANCE AWARD AGREEMENT
JANUARY 1, 20XX – DECEMBER 31, 20XX PERFORMANCE
CYCLE
Pursuant to this Qualified Performance Award Agreement (the
“Award Agreement”), CenterPoint Energy, Inc. (the
"Company") hereby grants to the Participant, an employee of the Company, these
target shares of Common Stock (the "Target Shares"), such number of shares being
subject to adjustment as provided in Section 14 of the CenterPoint Energy, Inc.
2009 Long Term Incentive Plan (the "Plan"), conditioned upon the Company's
achievement of the Performance Goals over the course of the 20XX – 20XX
Performance Cycle, and subject to the following terms and
conditions:
1. Relationship to the
Plan. This grant of Target Shares is subject to all of the
terms, conditions and provisions of the Plan in effect on the date hereof and
administrative interpretations thereunder, if any, adopted by the
Committee. To the extent that any provision of this Award Agreement
conflicts with the express terms of the Plan, it is hereby acknowledged and
agreed that the terms of the Plan shall control and, if necessary, the
applicable provisions of this Award Agreement shall be hereby deemed amended so
as to carry out the purpose and intent of the Plan. References to the
Participant herein also include the heirs or other legal representatives of the
Participant.
2. Definitions. Except
as defined herein, capitalized terms shall have the same meanings ascribed to
them under the Plan. For purposes of this Award
Agreement:
"Achievement
Percentage" means the percentage of achievement determined by the
Committee after the end of the Performance Cycle in accordance with Section 4
that reflects the extent to which the Company achieved the Performance Goals
during the Performance Cycle.
"Change in Control
Closing Date" means the date a Change in Control is consummated during
the Performance Cycle.
"Disability"
means that the Participant is (i) eligible for and in receipt of benefits
under the Company's long-term disability plan and (ii) not eligible for
Retirement.
"Employment"
means employment with the Company or any of its
Subsidiaries.
"Performance
Cycle" means the period beginning on January 1, 20XX and ending on
December 31, 20XX.
"Retirement"
means a Separation from Service on or after the attainment of age 55 and with at
least five years of service with the Company; provided,
however, that such Separation from Service is not by the Company for
Cause. For purposes of this Award Agreement, "Cause" means the
Participant's (a) gross negligence in the performance of his or her duties, (b)
intentional and continued failure to perform his or her duties, (c) intentional
engagement in conduct which is materially injurious to the Company or its
Subsidiaries (monetarily or otherwise) or (d) conviction of a felony or a
misdemeanor involving moral
1
turpitude. For this purpose, an act or failure
to act on the part of the Participant will be deemed "intentional" only if done
or omitted to be done by the Participant not in good faith and without
reasonable belief that his or her action or omission was in the best interest of
the Company, and no act or failure to act on the part of the Participant will be
deemed "intentional" if it was due primarily to an error in judgment or
negligence.
"Separation from
Service" means a separation from service with the Company or any of its
Subsidiaries within the meaning of Treasury Regulation § 1.409A-1(h) (or any
successor regulation).
"Target
Shares" means the actual number of shares originally granted to the
Participant pursuant to this Award Agreement, with such number of shares to be
actually awarded to the Participant at the close of the Performance Cycle if the
Company attains an Achievement Percentage of 100% for the Performance Goals
associated with such Target Shares.
"Vested
Shares" means the shares of Common Stock actually awarded to the
Participant following the Participant's satisfaction of the vesting provisions
of Section 5 and, if applicable, the determination by the Committee of the
extent to which the Company has achieved the Performance Goals for the
Performance Cycle pursuant to Section 4.
3. Establishment of
Award Account. The grant of Target Shares pursuant to this
Award Agreement shall be implemented by a credit to a bookkeeping account
maintained by the Company evidencing the accrual in favor of the Participant of
the unfunded and unsecured right to receive shares of Common Stock of the
Company, which right shall be subject to the terms, conditions and restrictions
set forth in the Plan and to the further terms, conditions and restrictions set
forth in this Award Agreement. Except as otherwise provided in this
Award Agreement, the Target Shares of Common Stock credited to the Participant’s
bookkeeping account may not be sold, assigned, transferred, pledged or otherwise
encumbered until the Participant has been registered as a holder of shares of
Common Stock on the records of the Company as provided in Section 6 or 7 of this
Award Agreement.
4. Award
Opportunity.
(a) The
Performance Goals established for the Performance Cycle are attached hereto and
made a part hereof for all purposes. Except as otherwise provided in
Section 5(b)(ii) and Section 6, the Vested Shares awarded to the Participant
shall be the product of the number of Target Shares and the Achievement
Percentage that is based upon the Committee's determination of whether and to
what extent the Performance Goals have been achieved during the Performance
Cycle.
(b) No
later than 60 days after the close of the Performance Cycle, the Committee shall
determine the extent to which each Performance Goal has been
achieved. If the Company has performed at or above the threshold
level of achievement for a Performance Goal, the Achievement Percentage shall be
between 50% and 150%, with a target level of achievement resulting in an
Achievement Percentage of 100%. In no event shall the Achievement
Percentage exceed 150%. The combined level of achievement is the sum
of the weighted achievements of the Performance Goals as approved by the
Committee. Upon completing its determination of the level at which the
Performance Goals have been achieved, the Committee shall notify the
Participant, in the form and manner as determined
2
by the Committee, of the number of Vested Shares that will
be issued to the Participant pursuant to Section 7.
5. Vesting
of Shares.
(a) Unless
earlier forfeited in accordance with Section 5(b)(i) or unless earlier vested in
accordance with Section 5(b)(ii) or Section 6, the Participant's right to
receive shares pursuant to this Award Agreement, if any, shall vest on the date
the Committee determines that each Performance Goal has been met (as provided in
Section 4). As soon as administratively practicable, but in no event
later than 70 days, after the close of the Performance Cycle, the Committee
shall notify the Participant as required by Section 4 of the level at which the
Performance Goals established for the Performance Cycle have been
achieved.
(b) If
the Participant's Separation from Service date occurs prior to the close of the
Performance Cycle or the occurrence of a Change in Control, then the applicable
of the following clauses shall apply with respect to the Target Shares subject
to this Award Agreement:
(i) Forfeiture
of Entire Award. If the Participant's Employment is
terminated, such that the Participant has a Separation from Service, by the
Company or any of its Subsidiaries or by the Participant for any reason other
than due to death, Disability or Retirement, then the Participant's right to
receive any Target Shares shall be forfeited in its entirety as of the date of
such Separation from Service.
(ii) Death or
Disability. If the Participant's Employment is terminated due
to death or Disability, the Participant's right to receive the Target Shares
shall vest on the date of such Separation from Service in the proportion of the
number of days elapsed in the Performance Cycle as of the date of Separation
from Service by the total number of days in the Performance
Cycle. The Participant's right to receive any additional shares
pursuant to this Award Agreement shall be forfeited at such
time.
(iii) Retirement. If
the Participant's Employment is terminated due to Retirement, the Participant's
right to receive shares pursuant to this Award Agreement, if any, shall vest on
the date the Committee determines that each Performance Goal has been met (as
provided in Section 4) in a pro-rata amount determined by multiplying (1) the
number of Vested Shares awarded to the Participant based upon the
Committee's determination of achievement of Performance Goals as provided in
Section 4, by (2) a fraction, the numerator of which is the number of days
elapsed in the Performance Cycle as of the date of the Participant's Separation
from Service, and the denominator of which is the total number of days in the
Performance Cycle. The Participant's right to receive any additional
shares pursuant to this Award Agreement shall be forfeited at such
time.
(c) In
accordance with the provisions of this Section 5, the Vested Shares shall be
distributed as provided in Section 7 hereof.
6. Distribution Upon a
Change in Control. Notwithstanding anything herein to the
contrary and without regard to the Performance Goals, if there is a Change in
Control during
3
the Performance Cycle, upon the Change in Control Closing
Date, the Participant's right to receive the Target Shares shall vest and be
settled by the distribution to the Participant of:
(a) shares
of Common Stock equal to the Target Shares; plus
(b) shares
of Common Stock (rounded up to the nearest whole share) having a Fair Market
Value equal to the amount of dividends that would have been declared on the
number of such shares determined under clause (a) above during the period
commencing at the beginning of the Performance Cycle and ending on the date
immediately preceding the Change in Control Closing Date.
In lieu of the foregoing distribution in shares, the
Committee, in its sole discretion, may direct that such distribution be made to
the Participant in a lump cash payment equal to:
(x) the
product of (i) the Fair Market Value per share of Common Stock on the date
immediately preceding the Change in Control Closing Date and (ii) the Target
Shares; plus
(y) the
amount of dividends that would have been declared on the number of shares of
Common Stock determined under clause (a) above during the period commencing at
the beginning of the Performance Cycle and ending on the date immediately
preceding the Change in Control Closing Date.
Such distribution, whether in the form of shares of Common
Stock or, if directed by the Committee, in cash, shall be made to the
Participant no later than the 70th day after the Change in Control Closing Date,
and shall satisfy the rights of the Participant and the obligations of the
Company under this Award Agreement in full. In the event a Change in
Control occurs after the Participant has had a Separation from Service due to
Retirement, the Target Shares such Participant shall receive under this Section
6 shall be pro-rated based on the number of days that elapsed in the Performance
Cycle as of his Separation from Service date over the total number of days in
the Performance Cycle.
7. Distribution
of Vested Shares.
(a) If
the Participant's right to receive shares pursuant to this Award Agreement has
vested pursuant to Section 5(a) or Section 5(b)(iii), a number of shares of
Common Stock equal to the number of Vested Shares shall be registered in the
name of the Participant and shall be delivered to the Participant no later than
March 15th of the calendar year following the calendar year in which occurs the
last day of the Performance Cycle.
(b) If
the Participant's right to receive shares pursuant to this Award Agreement has
vested pursuant to Section 5(b)(ii), a number of shares of Common Stock equal to
the number of Vested Shares shall be registered in the name of the Participant
(or his or her estate, if applicable) and shall be delivered to the Participant
(or his or her estate, if applicable) not later than the 70th day after the
Participant's Separation from Service date.
(c) The
Company shall have the right to withhold applicable taxes from any such
distribution of Vested Shares or from other compensation payable to the
Participant at the time of such vesting and delivery pursuant to Section 11 of
the Plan (but subject to compliance with the requirements of Section 409A of the
Internal Revenue Code ("Section 409A"), if applicable).
4
(d) Upon
delivery of the Vested Shares pursuant to Section 7(a) or 7(b) above, the
Participant shall also be entitled to receive a cash payment equal to the sum of
all dividends, if any, declared on the Vested Shares after the commencement of
the Performance Cycle but prior to the date the Vested Shares are delivered to
the Participant.
8. Confidentiality. The
Participant agrees that the terms of this Award Agreement are confidential and
that any disclosure to anyone for any purpose whatsoever (save and except
disclosure to financial institutions as part of a financial statement,
financial, tax and legal advisors, or as required by law) by the Participant or
his or her agents, representatives, heirs, children, spouse, employees or
spokespersons shall be a breach of this Award Agreement and the Company may
elect to revoke the grant made hereunder, seek damages, plus interest and
reasonable attorneys' fees, and take any other lawful actions to enforce this
Award Agreement.
9. Notices. For
purposes of this Award Agreement, notices to the Company shall be deemed to have
been duly given upon receipt of written notice by the Corporate Secretary of
CenterPoint Energy, Inc., 1111 Louisiana, Houston, Texas 77002, or to such other
address as the Company may furnish to the Participant.
Notices to the Participant shall be deemed effectively
delivered or given upon personal, electronic, or postal delivery of written
notice to the Participant, the place of Employment of the Participant, the
address on record for the Participant at the human resources department of the
Company, or such other address as the Participant hereafter designates by
written notice to the Company.
10. Shareholder
Rights. The Participant shall have no rights of a shareholder
with respect to the Target Shares, unless and until the Participant is
registered as the holder of shares of Common Stock.
11. Successors and
Assigns. This Award Agreement shall bind and inure to the
benefit of and be enforceable by the Participant, the Company and their
respective permitted successors and assigns except as expressly prohibited
herein and in the Plan. Notwithstanding anything herein or in the
Plan to the contrary, the Target Shares are transferable by the Participant to
Immediate Family Members, Immediate Family Member trusts, and Immediate Family
Member partnerships pursuant to Section 13 of the Plan.
12. No Employment
Guaranteed. Nothing in this Award Agreement shall give the
Participant any rights to (or impose any obligations for) continued Employment
by the Company or any Subsidiary or any successor thereto, nor shall it give
such entities any rights (or impose any obligations) with respect to continued
performance of duties by the Participant.
13. Waiver.
Failure of either party to demand strict compliance with any of the terms
or conditions hereof shall not be deemed a waiver of such term or condition, nor
shall any waiver by either party of any right hereunder at any one time or more
times be deemed a waiver of such right at any other time or times. No
term or condition hereof shall be deemed to have been waived except by written
instrument.
14. Exclusion from
Section 409A. At all times prior to the date that the
Committee determines that
each Performance Goal has been met (following the last date of the Performance
Cycle) or, if applicable under Section 6 or 7(b), the Change in Control Closing
Date or the Participant's Separation from Service, respectively, the benefit
payable under this Award
5
Agreement is subject to a
substantial risk of forfeiture within the meaning of Treasury Regulation § 1.409A-1(d) (or any successor
regulation). Accordingly, this Award is not subject to Section
409A under the short term deferral exclusion, and this Award Agreement shall be
interpreted and administered consistent therewith.
15. Compliance with
Recoupment Policy. Any amounts payable, paid,
or distributed under this Award Agreement are subject to the recoupment policy
of the Company as in effect from time to time.
16. Modification of
Award Agreement. Any modification of this Award Agreement shall be
binding only if evidenced in writing and signed by an authorized representative
of the Company.
6
Exhibit
10(kk)(3)
CENTERPOINT ENERGY, INC.
2009 LONG TERM INCENTIVE PLAN
RESTRICTED STOCK UNIT AWARD AGREEMENT
(With Performance Goal)
Pursuant to this Restricted Stock Unit Award Agreement
("Award Agreement"), CenterPoint Energy, Inc. (the "Company") hereby grants to
the Participant, an employee of the Company, on the Award Date, a restricted
stock unit award of these units of Common Stock of the Company (the "RSU
Award"), pursuant to the CenterPoint Energy, Inc. 2009 Long Term Incentive Plan
(the "Plan"), which is a qualified Performance Award under the Plan, conditioned
upon the Company's achievement of the Performance Goals established by the
Committee over the course of the Vesting Period, and subject to the terms,
conditions and restrictions described in the Plan and as follows:
1. Relationship to the
Plan; Definitions. This RSU Award is subject to all of the terms,
conditions and provisions of the Plan in effect on the date hereof and
administrative interpretations thereunder, if any, adopted by the
Committee. Except as defined herein, capitalized terms shall have the
same meanings ascribed to them under the Plan. To the extent that any
provision of this Award Agreement conflicts with the express terms of the Plan,
it is hereby acknowledged and agreed that the terms of the Plan shall control
and, if necessary, the applicable provisions of this Award Agreement shall be
hereby deemed amended so as to carry out the purpose and intent of the
Plan. References to the Participant herein also include the heirs or
other legal representatives of the Participant. For purposes of this
Award Agreement:
"Award Date"
means the date this RSU Award is granted to the Participant.
"Change in Control
Closing Date" means the date a Change in Control (as defined in the Plan)
is consummated during the Vesting Period.
"Change in Control
Payment Date" means the following:
(i) If
the Participant is not
Retirement Eligible, then the Change in Control Payment Date shall be not later
than the 70th day after the Change in Control Closing Date (regardless of
whether or not the Participant is a Specified Employee); and
(ii) If
the Participant is
Retirement Eligible and the Change in Control is a Section 409A Change in
Control, then the Change in Control Payment Date shall be not later than the
70th day after the Change in Control Closing Date (regardless of whether or not
the Participant is a Specified Employee); and
(iii) If
the Participant is
Retirement Eligible, the Change in Control is not a Section 409A Change in
Control and the Participant is not a Specified
1
Employee, then the Change in Control Payment Date shall be
not later than the 70th day after the earlier of:
(1) the
Vesting Date; or
|
|
(2)
|
the Termination
Date.
|
(iv) If
the Participant is
Retirement Eligible, the Change in Control is not a Section 409A Change in
Control and the Participant is a Specified Employee, then the Change in Control
Payment Date shall be as follows:
|
|
(1)
|
if (x) the Participant is in continuous Employment
from the Change in Control Closing Date until and including the Vesting
Date or (y) the Participant's death occurs prior to the Vesting Date, then
the Change in Control Payment Date shall be not later than the 70th day
after the earlier of:
|
|
|
(a)
|
the Vesting Date;
or
|
|
|
(b)
|
the date of the Participant's death;
or
|
|
|
(2)
|
if the Participant's Employment terminates following
the Change in Control Closing Date, other than due to death, but prior to
the Vesting Date, then the Change in Control Payment Date shall be the
earlier of:
|
|
|
(a)
|
the second business day following the end of the
six-month period commencing on the Participant's Termination Date;
or
|
|
|
(b)
|
the date of the Participant's death, if death occurs
during such six-month period.
|
"Disability"
means that the Participant is both eligible for and in receipt of benefits under
the Company's long-term disability plan.
"Employment"
means employment with the Company or any of its
Subsidiaries.
"Performance
Goals" means the standards established by the Committee to determine in
whole or in part whether the units of Common Stock under the RSU Award shall
vest, which are attached hereto and made a part hereof for all
purposes.
"Retirement"
means a Separation from Service (i) on or after attainment of age 55 and
(ii) with at least five years of Employment; provided,
however, that such Separation from Service is not by the Company for
Cause. For purposes of this Award Agreement, "Cause" means the
Participant's (a) gross negligence in the performance of his or her duties, (b)
intentional and continued failure to perform his or her duties, (c) intentional
engagement in
2
conduct which is materially injurious to the Company or its
Subsidiaries (monetarily or otherwise) or (d) conviction of a felony or a
misdemeanor involving moral turpitude. For this purpose, an act or
failure to act on the part of the Participant will be deemed "intentional" only
if done or omitted to be done by the Participant not in good faith and without
reasonable belief that his or her action or omission was in the best interest of
the Company, and no act or failure to act on the part of the Participant will be
deemed "intentional" if it was due primarily to an error in judgment or
negligence.
"Retirement
Eligible" means the Participant (i) is or will be age 55 or older and
(ii) has or will have at least five years of Employment, on or after the Award
Date but prior to the calendar year in which the Vesting Date
occurs.
"Section
409A" means Code Section 409A and the Treasury regulations and guidance
issued thereunder.
"Section 409A Change
in Control" means a Change in Control that satisfies the requirements of
a change in control for purposes of Code Section 409A(a)(2)(A)(v) and the
Treasury regulations and guidance issued thereunder.
"Separation from
Service" means a separation from service with the Company or any of its
Subsidiaries within the meaning of Treasury Regulation § 1.409A-1(h) (or any
successor regulation).
"Specified
Employee" has the meaning of that term under Code Section
409A(a)(2)(B)(i) and the Treasury regulations and guidance issued
thereunder.
"Termination
Date" means the date of the Participant's Separation from
Service.
"Vesting
Date" means [_________,
20XX].
"Vesting
Period" means the period commencing on the Award Date and ending on the
Vesting Date.
2. Establishment of RSU
Award Account. The grant of units of Common Stock of the
Company pursuant to this Award Agreement shall be implemented by a credit to a
bookkeeping account maintained by the Company evidencing the accrual in favor of
the Participant of the unfunded and unsecured right to receive such units of
Common Stock, which right shall be subject to the terms, conditions and
restrictions set forth in the Plan and to the further terms, conditions and
restrictions set forth in this Award Agreement. Except as otherwise
provided in Section 10 of this Award Agreement, the units of Common Stock
credited to the Participant's bookkeeping account may not be sold, assigned,
transferred, pledged or otherwise encumbered until the Participant has been
registered as the holder of shares of Common Stock on the records of the
Company, as provided in Sections 4, 5 or 6 of this Award
Agreement.
3. Vesting of RSU
Award. Unless earlier (a) vested or forfeited pursuant to this
Section 3 or Section 4 below or (b) vested upon the occurrence of a Change in
Control pursuant to Section 5 below, the Participant's right to receive shares
of Common Stock (if any)
3
under this Award Agreement shall vest on the Vesting
Date. No later than 60 days after the Vesting Date, the Committee
shall determine the extent to which the Performance Goal has been
achieved. Upon completing its determination of the level at which the
Performance Goal has been achieved, the Committee shall notify the Participant,
in the form and manner as determined by the Committee, of the number of shares
of Common Stock (if any) under this Award Agreement that will be issued to the
Participant pursuant to Section 6. Except as provided in Sections 4
and 5 below, the Participant must be in continuous Employment during the Vesting
Period in order for the RSU Award to vest; otherwise, all such units shall be
forfeited as of the Participant's Termination Date.
4. Effect
of Separation from Service; Timing of Distribution.
(a) Separation
from Service Prior to the Vesting Date or Change in
Control. Notwithstanding Section 3 above, if prior to (i) the
Vesting Date or (ii) the occurrence of a Change in Control, the Participant's
Separation from Service occurs due to Retirement, death or Disability,
then:
(1) Retirement. In
the event of Retirement, the Participant shall vest in the right to receive a
number, if any, of the shares of Common Stock (rounded up to the nearest whole
share) determined by multiplying (x) the total number of units of Common Stock
subject to this Award Agreement based upon the Committee's determination of the
achievement of the Performance Goal after the end of the Vesting Period, as
provided in Section 3, by (y) a fraction, the numerator of which is the number
of days that have elapsed from the Award Date to the Participant's Termination
Date, and the denominator of which is the total number of days in the Vesting
Period; or
(2) Death or
Disability. In the event of the Participant's death or
Separation from Service due to Disability, without regard to the Performance
Goals, the Participant shall vest in the right to receive a number of the shares
of Common Stock (rounded up to the nearest whole share) determined by
multiplying (x) the total number of units of Common Stock granted subject to
this Award Agreement by (y) a fraction, the numerator of which is the number of
days that have elapsed from the Award Date to the Participant's Termination
Date, and the denominator of which is the total number of days in the Vesting
Period.
(b) Timing of
Distribution.
(1) Retirement. If
the Participant is entitled to a benefit pursuant to Section 4(a)(1) hereof, a
number of shares of Common Stock equal to the number of vested shares of Common
Stock subject to this Award Agreement (as determined by the Committee in
accordance with Section 3 and Section 4(a)(1), if any) shall be registered in
the name of the Participant and delivered to the Participant not later than the
70th day after the Vesting Date.
4
(2) Death. If
the Participant is entitled to a benefit pursuant to Section 4(a)(2) hereof due
to the Participant's death, the number of shares of Common Stock determined in
accordance with Section 4(a)(2) shall be registered in the name of the
Participant's estate and delivered to the Participant's estate as soon as
practicable but not later than the 70th day after the date of the Participant's
death.
(3) Disability.
(A) Specified
Employee and Retirement Eligible. If the Participant (i) is
entitled to a benefit pursuant to Section 4(a)(2) hereof due to the
Participant's Separation from Service due to Disability, (ii) is a Specified
Employee, and (iii) is Retirement Eligible, the number of shares of Common Stock
determined in accordance with Section 4(a)(2) shall be registered in the name of
the Participant and delivered to the Participant on the date that is the earlier
of (x) the second business day following the end of the six-month period
commencing on the Participant's Termination Date or (y) the Participant's date
of death, if death occurs during such six-month period.
(B) All Other
Participants. Except as provided in Section 4(b)(3)(A), if the
Participant is entitled to a benefit pursuant to Section 4(a)(2) hereof due to
the Participant's Separation from Service due to Disability, the number of
shares of Common Stock determined in accordance with Section 4(a)(2) shall be
registered in the name of the Participant and delivered to the Participant as
soon as practicable but not later than the 70th day after the date of the
Participant's Termination Date.
(c) Dividend
Equivalents. Upon the date of delivery of shares of Common
Stock under this Section 4, the Participant shall also be entitled to receive
Dividend Equivalents for the period from the Award Date to the date such vested
shares of Common Stock are distributed to the Participant (in accordance with
the requirements of Section 409A, to the extent applicable).
5. Distribution Upon a
Change in Control. Notwithstanding any provision of this Award
Agreement to the contrary, if during the Participant's Employment and prior to
the end of the Vesting Period or an accelerated vesting event under Section 4
above there is a Change in Control of the Company, then, upon the Change in
Control Closing Date and without regard to the Performance Goal, the
Participant's right to receive the unvested units of Common Stock subject to
this Award Agreement shall be vested and settled by a distribution, on the
Change in Control Payment Date, to the Participant of:
(a) The
number of units of Common Stock subject to this Award Agreement not previously
vested or forfeited pursuant to Sections 3 or 4 above, plus
5
(b) Dividend
Equivalents in the form of shares of Common Stock (rounded up to the nearest
whole share) for the period commencing on the Award Date and ending on the date
immediately preceding the Change in Control Closing Date;
with such shares of Common Stock registered in the name of
the Participant and delivered to the Participant. In lieu of the
foregoing distribution in shares, the Committee, in its sole discretion, may
direct that such distribution be made to the Participant in a lump sum cash
payment equal to:
(x) The
product of (i) the Fair Market Value per share of Common Stock on the date
immediately preceding the Change in Control Closing Date and (ii) the number of
units of Common Stock subject to this Award Agreement not previously vested or
forfeited pursuant to Sections 3 or 4 above, plus
(y) Dividend
Equivalents for the period commencing on the Award Date and ending on the date
immediately preceding the Change in Control Closing Date;
with such cash payment to be made on the Change in Control
Payment Date. Such distribution under this Section 5, whether in the
form of shares of Common Stock or, if directed by the Committee, in cash, shall
satisfy the rights of the Participant and the obligations of the Company under
this Award Agreement in full.
6. Payment of RSU Award
Under Section 3. Upon the vesting of the Participant's right
to receive the shares of Common Stock pursuant to Section 3 under this Award
Agreement, a number of shares of Common Stock equal to the number of vested
shares of Common Stock subject to this Award Agreement (as determined by the
Committee in accordance with Section 3, if any) shall be registered in the name
of the Participant and delivered to the Participant not later than the 70th day
after the Vesting Date. Moreover, upon the date of delivery of shares
of Common Stock, the Participant shall also be entitled to receive Dividend
Equivalents for the period commencing on the Award Date and ending on the date
such vested shares of Common Stock are distributed to the Participant (in
accordance with the requirements of Section 409A, to the extent
applicable).
7. Confidentiality. The
Participant agrees that the terms of this Award Agreement are confidential and
that any disclosure to anyone for any purpose whatsoever (save and except
disclosure to financial institutions as part of a financial statement,
financial, tax and legal advisors, or as required by law) by the Participant or
his or her agents, representatives, heirs, children, spouse, employees or
spokespersons shall be a breach of this Award Agreement and the Company may
elect to revoke the grant made hereunder, seek damages, plus interest and
reasonable attorneys' fees, and take any other lawful actions to enforce this
Award Agreement.
8. Notices. For
purposes of this Award Agreement, notices to the Company shall be deemed to have
been duly given upon receipt of written notice by the Corporate Secretary of
CenterPoint Energy, Inc., 1111 Louisiana, Houston, Texas 77002, or to such other
address as the Company may furnish to the Participant.
6
Notices to the Participant shall be deemed effectively
delivered or given upon personal, electronic, or postal delivery of written
notice to the Participant, the place of Employment of the Participant, the
address on record for the Participant at the human resources department of the
Company, or such other address as the Participant hereafter designates by
written notice to the Company.
9. Shareholder
Rights. The Participant shall have no rights of a shareholder
with respect to the units of Common Stock subject to this Award Agreement,
unless and until the Participant is registered as the holder of such shares of
Common Stock.
10. Successors and
Assigns. This Award Agreement shall bind and inure to the
benefit of and be enforceable by the Participant, the Company and their
respective permitted successors and assigns except as expressly prohibited
herein and in the Plan. Notwithstanding anything herein or in the
Plan to the contrary, the units of Common Stock are transferable by the
Participant to Immediate Family Members, Immediate Family Member trusts, and
Immediate Family Member partnerships pursuant to Section 13 of the
Plan.
11. No Employment
Guaranteed. Nothing in this Award Agreement shall give the
Participant any rights to (or impose any obligations for) continued Employment
by the Company or any
Subsidiary, or any successor thereto, nor shall it give such entities any rights
(or impose any obligations) with respect to continued performance of duties by
the Participant.
12. Waiver. Failure
of either party to demand strict compliance with any of the terms or conditions
hereof shall not be deemed a waiver of such term or condition, nor shall any
waiver by either party of any right hereunder at any one time or more times be
deemed a waiver of such right at any other time or times. No term or
condition hereof shall be deemed to have been waived except by written
instrument.
13. Compliance with
Section 409A. It is the intent of the Company and the
Participant that the provisions of the Plan and this Award Agreement comply with
Section 409A and will be interpreted and administered consistent
therewith. Accordingly, (i) no adjustment to the RSU Award pursuant
to Section 14 of the Plan and (ii) no substitutions of the benefits under this
Award Agreement, in each case, shall be made in a manner that results in
noncompliance with the requirements of Section 409A, to the extent
applicable. The foregoing notwithstanding, if the Participant is not
Retirement Eligible, then at all times prior to the payment date, the benefit
payable under this Award Agreement is subject to a substantial risk of
forfeiture within the meaning of Treasury Regulation § 1.409A-1(d) (or any
successor regulation) and, accordingly, with respect to such Participant, this
RSU Award is not subject to Section 409A under the short term deferral
exclusion, and this Award Agreement shall be interpreted and administered
consistent therewith.
14. Withholding. The
Company shall have the right to withhold applicable taxes from any distribution
of the Common Stock (including, but not limited to, Dividend Equivalents) or
from other cash compensation payable to the Participant at the time of such
vesting and delivery pursuant to Section 11 of the Plan (but subject to
compliance with the requirements of Section 409A, if
applicable).
7
15. Compliance with
Recoupment Policy. Any amounts payable, paid, or
distributed under this Award Agreement are subject to the recoupment policy of
the Company as in effect from time to time.
16. Modification of
Award Agreement. Any modification of this Award Agreement is
subject to Section 13 hereof and shall be binding only if evidenced in writing
and signed by an authorized representative of the Company.
8
Exhibit 10(ll)
CenterPoint
Energy, Inc.
Summary of Non-Employee Director
Compensation
The
following is a summary of compensation paid to the non-employee directors of
CenterPoint Energy, Inc. (the “Company”) effective April 24, 2008. For
additional information regarding the compensation of the non-employee directors,
please read the definitive proxy statement relating to the Company’s 2010 annual
meeting of shareholders to be filed pursuant to Regulation 14A.
|
•
|
Annual
retainer fee of $50,000 for Board membership;
|
||
|
•
|
Fee
of $2,000 for each Board or Committee meeting attended;
|
||
|
•
|
Supplemental
annual retainer of $15,000 for serving as a chairman of the Audit
Committee;
|
||
|
•
|
Supplemental
annual retainer of $10,000 for serving as a chairman of the Compensation
Committee; and
|
||
|
•
|
Supplemental
annual retainer of $5,000 for serving as a chairman of any other Board
committee.
|
The
Chairman receives the compensation payable to other non-employee directors plus
supplemental compensation pursuant to a letter agreement with the Company
incorporated by reference to Exhibit 10(p) to the Company’s Annual Report on
Form 10-K for the year ended December 31, 2007.
Stock Grants. Each
non-employee director may also receive an annual grant of up to 5,000 shares of
CenterPoint Energy common stock which vest in one-third increments on the first,
second and third anniversaries of the grant date. Upon the initial nomination to
the Board, in addition to the annual grant, a non-employee director may be
granted a one-time grant of up to 5,000 shares of CenterPoint Energy common
stock.
Deferred Compensation Plan.
Directors may elect each year to defer all or part of their annual
retainer fees, including committee chairman fees, and meeting fees.
Directors participating in these plans may elect to receive distributions of
their deferred compensation and interest in three ways: (i) an early
distribution of either 50% or 100% of their account balance in any year that is
at least four years from the year of deferral up to the year in which they reach
age 70, (ii) a lump sum distribution payable in the year after they reach age 70
or upon leaving the Board of Directors, whichever is later, or (iii) 15 annual
installments beginning on the first of the month coincident with or next
following age 70 or upon leaving the Board of Directors, whichever is
later.
Director Benefits Plan.
Non-employee directors elected to the Board before 2004 participatd in a
director benefits plan under which a director who served at least one full year
would receive an annual cash amount equal to the annual retainer (excluding any
supplemental retainer) in effect when the director terminated service. In
accordance with the transition rules under Section 409A of the Internal
Revenue Code, the Board amended the plan to freeze future benefit accruals under
the plan effective December 31, 2008 and to provide commencement of payments as
of February 1, 2009. Each active director participating in this plan was given
the opportunity to make a one-time irrevocable election by December 31,
2008 as to the payment form. Each active director elected a lump sum
payment; therefore, all accrued benefits under the plan were paid on February 1,
2009.
Executive Life Insurance Plan.
Non-employee directors who were elected to the Board before 2001
participate in CenterPoint Energy’s executive life insurance plan. This plan
provides endorsement split-dollar life insurance with a death benefit of
$180,000 with coverage continuing after the director’s termination of service at
age 65 or later. Directors elected to the Board after 2000 may not participate
in this plan.
Exhibit 10(mm)
CenterPoint
Energy, Inc.
Summary
of Named Executive Officer Compensation
The following
is a summary of compensation paid to the named executive officers of CenterPoint
Energy, Inc. (the “Company”). For additional information regarding the
compensation of the named executive officers, please read the definitive proxy
statement relating to the Company’s 2010 annual meeting of shareholders to be
filed pursuant to Regulation 14A.
Base Salary.
The following table sets forth the annual base salary of the Company’s
named executive officers effective April 1, 2010:
|
Name
and Position
|
Base
Salary
|
|||
|
David
M. McClanahan
President
and Chief Executive Officer
|
$
|
1,100,000
|
||
|
Gary
L. Whitlock
Executive
Vice President
and
Chief Financial Officer
|
$
|
525,000
|
||
|
Scott
E. Rozzell
Executive
Vice President, General
Counsel
and Corporate Secretary
|
$
|
490,000
|
||
|
Thomas
R. Standish
Senior
Vice President and Group
President
— Regulated Operations
|
$
|
472,000
|
||
|
C.
Gregory Harper
Senior
Vice President and Group President,
Pipelines
and Field Services
|
$
|
355,000
|
||
|
|
||||
Short Term Incentive
Plan. Annual bonuses are paid to the Company’s named executive officers
pursuant to the Company’s short term incentive plan, which provides for cash
bonuses based on the achievement of certain performance objectives approved in
accordance with the terms of the plan at the commencement of the year.
Information regarding awards to the Company’s named executive officers under the
short term incentive plan is provided in definitive proxy statements relating to
the Company’s annual meeting of shareholders.
Long Term Incentive
Plan. Under the Company’s long term incentive plan, the Company’s named
executive officers may receive grants of (i) stock option awards,
(ii) performance share awards, (iii) performance unit awards and/or
(iv) stock awards. The current forms of the applicable award agreements
pursuant to the Company’s long term incentive plan are included as exhibits
hereto.
Exhibit
12
CENTERPOINT ENERGY, INC.
AND SUBSIDIARIES
COMPUTATION
OF RATIOS OF EARNINGS TO FIXED CHARGES
(Millions
of Dollars)
|
2005
|
2006
|
2007
(1)
|
2008 (1)
|
2009
(1)
|
||||||||||||||||
|
Income
from continuing operations
|
$ | 220 | $ | 427 | $ | 395 | $ | 446 | $ | 372 | ||||||||||
| Equity in earnings of unconsolidated affiliates | (6 | ) | (6 | ) | (16 | ) | (51 | ) | (15 | ) | ||||||||||
|
Income
taxes for continuing operations
|
150 | 59 | 193 | 277 | 176 | |||||||||||||||
|
Capitalized
interest
|
(4 | ) | (10 | ) | (22 | ) | (12 | ) | (4 | ) | ||||||||||
| 360 | 470 | 550 | 660 | 529 | ||||||||||||||||
|
Fixed
charges, as defined:
|
||||||||||||||||||||
|
Interest
|
718 | 608 | 632 | 604 | 644 | |||||||||||||||
|
Capitalized
interest
|
4 | 10 | 22 | 12 | 4 | |||||||||||||||
|
Interest component of rentals
charged to operating expense
|
12 | 19 | 16 | 15 | 12 | |||||||||||||||
|
Total fixed
charges
|
734 | 637 | 670 | 631 | 660 | |||||||||||||||
|
Earnings,
as defined
|
$ | 1,094 | $ | 1,107 | $ | 1,220 | $ | 1,291 | $ | 1,189 | ||||||||||
|
Ratio
of earnings to fixed charges
|
1.49 | 1.74 | 1.82 | 2.05 | 1.80 | |||||||||||||||
|
|
(1)
|
Excluded
from the computation of fixed charges for the years ended December 31,
2007, 2008 and 2009 is interest income of $4 million, interest
expense of $9 million and interest income of $3 million,
respectively, which is included in income tax
expense.
|
Exhibit
21
SIGNIFICANT
SUBSIDIARIES OF CENTERPOINT ENERGY,
INC.
The following subsidiaries are deemed “significant
subsidiaries” pursuant to Item 601(b) (21) of Regulation S-K:
Utility Holding, LLC, a Delaware limited liability company
and a direct wholly owned subsidiary of CenterPoint Energy, Inc.
CenterPoint Energy Investment Management, Inc., a Delaware
corporation and an indirect wholly owned subsidiary of CenterPoint Energy,
Inc.
CenterPoint Energy Resources Corp., a Delaware corporation
and an indirect wholly owned subsidiary of CenterPoint Energy, Inc.
CenterPoint Energy Houston Electric, LLC, a Texas limited
liability company and an indirect wholly owned subsidiary of CenterPoint Energy,
Inc.
CenterPoint Energy Services, Inc., a Delaware corporation
and an indirect wholly owned subsidiary of CenterPoint Energy,
Inc.
CenterPoint Energy Gas Transmission Company, a Delaware
corporation and an indirect wholly owned subsidiary of CenterPoint Energy,
Inc.
CenterPoint Energy Field Services, Inc., a Delaware
corporation and an indirect wholly owned subsidiary of CenterPoint Energy,
Inc.
(1) Pursuant to Item 601(b) (21) of Regulation S-K,
registrant has omitted the names of subsidiaries, which considered in the
aggregate as a single subsidiary, would not constitute a “significant
subsidiary” (as defined under Rule 1-02(w) of Regulation S-X) as of December 31,
2009.
Exhibit
23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
We consent to the incorporation by reference in
Registration Statement Nos. 333-155475, 333-153916 and 333-114543 on Form S-3;
Registration Statement Nos. 333-159586, 333-105773, 333-149757, 333-101202, as
amended, and 333-115976, as amended, on Form S-8; Post-Effective Amendment No. 1
to Registration Statement No. 333-33303-99 on Form S-3; Post Effective Amendment
No. 1 to Registration Statement Nos. 333-32413-99, 333-49333-99, 333-38188-99,
333-60260-99 and 333-98271-99 on Form S-8; and Post-Effective Amendment No. 5 to
Registration Statement No. 333-11329-99 on Form S-8 of our reports dated
February 26, 2010, relating to the consolidated financial statements and
financial statement schedules of CenterPoint Energy, Inc. and subsidiaries (the
“Company”), and the effectiveness of the Company’s internal control over
financial reporting, appearing in this Annual Report on Form 10-K of CenterPoint
Energy, Inc. for the year ended December 31, 2009.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 26, 2010
Exhibit
31.1
CERTIFICATIONS
I, David
M. McClanahan, certify that:
1. I
have reviewed this annual report on Form 10-K of CenterPoint
Energy, Inc.;
2. Based
on my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made, in
light of the circumstances under which such statements were made, not misleading
with respect to the period covered by this report;
3. Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
4. The
registrant’s other certifying officer(s) and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
(a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
(b)
|
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
|
|
(c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
|
(d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
5. The
registrant’s other certifying officer(s) and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
|
|
(a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
|
(b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
Date: February
26, 2010
|
/s/
David M. McClanahan
|
|
|
David
M. McClanahan
|
|
|
President
and Chief Executive Officer
|
Exhibit
31.2
CERTIFICATIONS
I, Gary
L. Whitlock, certify that:
1. I
have reviewed this annual report on Form 10-K of CenterPoint
Energy, Inc.;
2. Based
on my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made, in
light of the circumstances under which such statements were made, not misleading
with respect to the period covered by this report;
3. Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
4. The
registrant’s other certifying officer(s) and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
(a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
(b)
|
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
|
|
(c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
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(d)
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Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
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5. The
registrant’s other certifying officer(s) and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
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(a)
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All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
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(b)
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Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
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Date: February
26, 2010
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/s/
Gary L. Whitlock
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Gary
L. Whitlock
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Executive
Vice President and Chief Financial
Officer
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Exhibit
32.1
CERTIFICATION
PURSUANT TO
18 U.S.C.
SECTION 1350,
AS
ADOPTED PURSUANT TO SECTION 906
OF THE
SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of
CenterPoint Energy, Inc. (the “Company”) on Form 10-K for the year
ended December 31, 2009 (the “Report”), as filed with the Securities and
Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive
Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge,
that:
1. The
Report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
2. The
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the Company.
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/s/
David M. McClanahan
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David
M. McClanahan
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President
and Chief Executive Officer
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February 26,
2010
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Exhibit
32.2
CERTIFICATION
PURSUANT TO
18 U.S.C.
SECTION 1350,
AS
ADOPTED PURSUANT TO SECTION 906
OF THE
SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of
CenterPoint Energy, Inc. (the “Company”) on Form 10-K for the year
ended December 31, 2009 (the “Report”), as filed with the Securities and
Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial
Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge,
that:
1. The
Report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
2. The
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the Company.
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/s/
Gary L. Whitlock
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Gary
L. Whitlock
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Executive
Vice President and Chief Financial Officer
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February
26, 2010
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