UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
________________
Form 10-K
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(Mark
One)
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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, 2008
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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 1-13265
______________________________
CenterPoint
Energy Resources Corp.
(Exact
name of registrant as specified in its charter)
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Delaware
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76-0511406
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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
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Houston,
Texas 77002
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(713)
207-1111
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(Address
and zip code of principal executive offices)
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(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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6%
Convertible Subordinated Debentures due 2012
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New
York Stock Exchange
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Securities
registered pursuant to Section 12(g) of the Act:
None
CenterPoint
Energy Resources Corp. meets the conditions set forth in General Instruction
I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the
reduced disclosure format.
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes £ No R
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 £ No R
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 R 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
the registrant’s 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. R
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):
Large
accelerated filer o Accelerated
filer o Non-accelerated
filer þ Smaller
reporting company o
(Do
not check if a smaller reporting company)
Indicate
by check mark whether the registrant is a shell company (as defined by Rule
12b-2 of the Exchange Act).Yes £ No R
The
aggregate market value of the common equity held by non-affiliates as of June
30, 2008: None
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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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11
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Item
1B.
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17
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Item
2.
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17
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Item
3.
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18
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Item
4.
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18
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PART II
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Item
5.
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18
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Item
6.
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18
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Item
7.
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19
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Item
7A.
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33
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Item
8.
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35
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Item
9.
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66
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Item
9A(T).
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66
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Item
9B.
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66
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PART III
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Item
10.
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66
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Item
11.
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66
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Item
12.
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67
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Item
13.
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67
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Item
14.
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67
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PART IV
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Item
15.
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67
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Ex.
12
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Computation of Ratios of Earnings to Fixed Charges | |
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Ex.
23
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Consent of Deloitte & Touche LLP | |
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Ex.
31.1
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Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan | |
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Ex.
31.2
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Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock | |
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Ex.
32.1
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Section 1350 Certification of David M. McClanahan | |
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Ex.
32.2
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Section 1350 Certification of Gary L. Whitlock |
We meet
the conditions specified in General Instruction I(1)(a) and (b) of Form 10-K and
are thereby permitted to use the reduced disclosure format for wholly owned
subsidiaries of reporting companies specified therein. Accordingly, we have
omitted from this report the information called for by Item 4 (Submission of
Matters to a Vote of Security Holders), Item 10 (Directors, Executive Officers,
and Corporate Governance), Item 11 (Executive Compensation), Item 12 (Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters) and Item 13 (Certain Relationships and Related Transactions, and
Director Independence) of Form 10-K. In lieu of the information called for by
Item 6 (Selected Financial Data) and Item 7 (Management’s Discussion and
Analysis of Financial Condition and Results of Operations) of Form 10-K, we have
included, under Item 7, Management’s Narrative Analysis of the Results of
Operations to explain the reasons for material changes in the amount of revenue
and expense items between 2006, 2007 and 2008.
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
OUR
BUSINESS
Overview
We own
and operate natural gas distribution systems in six
states. Subsidiaries of ours own interstate natural gas pipelines and
gas gathering systems and provide various ancillary services. A
wholly owned subsidiary of ours offers variable and fixed-price physical natural
gas supplies primarily to commercial and industrial customers and electric and
gas utilities. References to “we,” “us,” and “our” mean CenterPoint
Energy Resources Corp. (CERC Corp., together with our subsidiaries,
CERC). We are an indirect wholly owned subsidiary of CenterPoint
Energy, Inc. (CenterPoint Energy), a public utility holding
company.
Our
reportable business segments are Natural Gas Distribution, Competitive Natural
Gas Sales and Services, Interstate Pipelines, Field Services and Other
Operations.
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 parent company’s 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). Our parent company’s
website address is www.centerpointenergy.com.
Except to the extent explicitly stated herein, documents and information on our
parent company’s website are not incorporated by reference herein.
Natural
Gas Distribution
Our
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 2008, 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 2008,
approximately 71% 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 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, which struck the upper Texas coast in September 2008. As of
December 31, 2008, Gas Operations has deferred approximately $4 million of
costs related to Hurricane Ike for recovery as part of future natural gas
distribution rate proceedings.
Supply and
Transportation. In 2008, 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 2008 included BP Canada
Energy Marketing Corp. (13.4% of supply volumes), Tenaska Marketing Ventures
(11.5%), Oneok Energy Marketing (10.2%), Coral Energy Resources (6.6%) and
Cargill, Inc. (5.8%). Numerous other suppliers provided the remaining
52.5% 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, 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 MMcf per day and
on-site storage facilities for 12 million gallons of propane (1.0 Bcf
natural gas equivalent). It owns liquefied natural gas plant facilities with a
12 million-gallon liquefied natural gas storage tank (1.0 Bcf natural
gas equivalent) and a production rate of 72 MMcf 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.
Assets
As of
December 31, 2008, Gas Operations owned approximately 70,000 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
We offer
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 2008,
CES marketed approximately 528 Bcf of natural gas, transportation and
related energy services to approximately 9,700 customers (including
approximately 9 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, and are served from offices located in Arkansas,
Illinois, Indiana, Louisiana, Minnesota, Missouri, Pennsylvania, Texas and
Wisconsin. The business has three operational functions: wholesale, retail and
intrastate pipelines, which are further described below.
Wholesale
Operations. 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 inter- and intra-state pipeline companies, and
include gas utilities, large industrial customers and electric generation
customers.
Retail
Operations. CES offers a variety of natural gas management
services to smaller commercial and industrial customers, municipalities,
educational institutions and hospitals, whose facilities are 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 sixteen states.
Intrastate Pipeline
Operations. CEIP primarily 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 32 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 2008, CES’ VaR averaged $1.5 million with
a high of $2.8 million.
The
CenterPoint Energy risk control policy, governed by CenterPoint Energy’s 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
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 227 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 1.1 Bcf per day on various inter- and intrastate pipelines
and approximately 8.8 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
Our
pipelines business operates interstate natural gas pipelines with gas
transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri,
Oklahoma and Texas. Our 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 Federal Energy Regulatory Commission (FERC). Our 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 2008,
approximately 15% 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. Effective April 1, 2008, MRT signed a
5-year extension of its firm transportation and storage contracts with
Laclede. 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 April 2008, CEGT completed the Phase III
expansion of the Carthage to Perryville pipeline. This expansion
included additional compression and authorization from the Pipeline and
Hazardous Materials Safety Administration (PHMSA) to operate the line at higher
pressures. The Carthage to Perryville pipeline can now operate at up to 1.5 Bcf
per day. CEGT filed with FERC on December 5, 2008 to increase the
Carthage to Perryville capacity to approximately 1.9 Bcf per day. The
expansion includes a new compressor unit at two of CEGT’s existing stations and
is currently projected to be placed in service in the second quarter of
2010.
Southeast Supply
Header. The Southeast Supply Header (SESH) pipeline project, a
joint venture between CEGT and Spectra Energy Corp., was placed into commercial
service on September 6, 2008. This new 270-mile pipeline, which extends from the
Perryville Hub, near Perryville, Louisiana, to an interconnection with the Gulf
Stream Natural Gas System near Mobile, Alabama, has a maximum design capacity of
approximately one Bcf per day. The pipeline represents a new source of natural
gas supply for the Southeast United States and offers greater supply diversity
to this region. Our share of SESH’s net construction costs is approximately
$625 million.
Assets
Our
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. We also own and operate 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. We
also own a 10% interest in the Bistineau storage facility located in Bienville
Parish, Louisiana, with the remaining interest owned and operated by Gulf
South
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Pipeline
Company, LP. Our 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
Our
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. Our interstate pipelines business
competes indirectly with other forms of energy, including electricity, coal and
fuel oils. The primary competitive factor is price. 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
Our field
services business operates gas gathering, treating, and processing facilities
and also provides operating and technical services and remote data monitoring
and communication services.
Our 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 1.3 Bcf
per day of natural gas and, either directly or through its 50% interest in a
joint venture, processes in excess of 240 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.
Our 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.
Assets
Our field
services business owns and operates approximately 3,600 miles of gathering
pipelines and processing plants that collect, treat and process natural gas from
approximately 150 separate systems located in major producing fields in
Arkansas, Louisiana, Oklahoma and Texas.
Competition
Our 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. Our field services business
competes indirectly with other forms of energy, including electricity, coal and
fuel oils. The primary competitive factor is price. 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 impacted 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 unallocated corporate costs and
inter-segment eliminations.
Financial
Information About Segments
For
financial information about our segments, see Note 12 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 intrastate 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.
Our
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 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.
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, CenterPoint
Energy filed with the FERC the required notification of its status as a public
utility holding company. In October 2006, 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 make allocations to public utilities regulated by the FERC under
the Federal Power Act. Although CenterPoint Energy provides services to its
subsidiaries through a service company, its service company is not subject to
the FERC’s service company rules.
State
and Local Regulation
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 Gas Operations serves 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. The request sought to establish uniform rates, charges and terms and
conditions of service for the cities and environs of the Texas Coast service
territory. Of the 47 cities, 23 either affirmatively approved or allowed the
filed rates to go into effect by operation of law. Nine other cities were
represented by the Texas Coast Utilities Coalition (TCUC) and 15 cities were
represented by the Gulf Coast Coalition of Cities (GCCC). In July 2008, Gas
Operations reached a settlement agreement with the GCCC. That settlement
agreement, if implemented across the entire Texas Coast service territory, would
allow Gas Operations a $3.4 million annual increase in revenues. The TCUC
cities denied the rate change request and Gas Operations
6
appealed
the denial of rates to the Railroad Commission. The Railroad Commission issued
an order in October 2008, which, if implemented across the entire Texas Coast
service territory, would result in an annual revenue increase of
$3.7 million. Both the Railroad Commission order and the settlement provide
for an annual rate adjustment mechanism to reflect changes in operating expenses
and revenues as well as changes in capital investment and associated changes in
revenue-related taxes. In December 2008, the Railroad Commission issued an order
on rehearing. Parties filed second motions for rehearing on this
order. On February 26, 2009, the Railroad Commission denied the second motions
on rehearing reaffirming its original decision. In December 2008, Gas
Operations implemented the approved rates for the nine TCUC cities and the
environs. Cities with settled rates have the opportunity to adopt the
rates established by the Railroad Commission or retain the rates agreed in their
settlements.
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 court ordered
the case remanded to the MPUC for reconsideration under the same principles the
MPUC had applied in previously granted waiver requests. The MPUC sought further
review of the court of appeals decision from the Minnesota Supreme Court, and in
July 2008, the Minnesota Supreme Court agreed to review the
decision. In January 2009, the Minnesota Supreme Court heard oral
arguments. While there is no deadline for a decision, a decision is expected by
the end of the third quarter of 2009. While no prediction can be made as to the
ultimate outcome, this matter will have no negative impact on our financial
condition, results of operations or cash flows.
In
November 2008, Gas Operations filed a request with the MPUC to increase its
rates for utility distribution service. If approved by the MPUC, the
proposed new rates would result in an overall increase in annual revenue of
$59.8 million. The proposed increase would allow Gas Operations to recover
increased operating costs, including higher bad debt and collection expenses,
the cost of improved customer service and inflationary increases in other
expenses. It also would allow recovery of increased costs related to
conservation improvement programs and provide a return for the additional
capital invested to serve its customers. In addition, Gas Operations is seeking
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. The MPUC is allowed ten months to issue a final
decision; however, an extension of time can occur in certain
circumstances.
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 PHMSA of the U.S. Department of
Transportation 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 our 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
7
technical
reviews, we believe compliance will require annual expenditures (capital and
operating costs combined) of approximately $17 to 24 million during the
initial 10-year period.
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, gas gathering and processing 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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restricting
the way we can handle or dispose of
wastes;
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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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requiring
remedial action to mitigate pollution conditions caused by our operations,
or attributable to former operations;
and
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enjoining
the operations of facilities deemed in non-compliance with permits issued
pursuant to such environmental laws and
regulations.
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In order
to comply with these requirements, we may need to spend substantial amounts and
devote other resources from time to time to:
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construct
or acquire new equipment;
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acquire
permits for facility operations;
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modify
or replace existing and proposed equipment;
and
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clean
up or decommission waste disposal areas, fuel storage and management
facilities and other locations and
facilities.
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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 requiring 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. While there is growing consensus that some form of global
climate change program will be adopted, it is too early to determine when, and
in what form, a regulatory scheme regarding greenhouse gas emissions will be
adopted or what specific impacts a new regulatory scheme might have on us and
our subsidiaries. However, as a distributor and transporter of natural gas and
consumer of natural gas in our pipeline and gathering businesses, our revenues,
operating costs and capital requirements could be adversely affected as a result
of any regulatory scheme that would reduce consumption of natural gas if
ultimately adopted.
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 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. We believe, however, that our operations will not be materially
adversely affected by such requirements, and the requirements are not expected
to be any more burdensome to us than to other similarly situated
companies.
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 United States
Environmental Protection Agency (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.
We and our predecessors operated manufactured gas plants (MGPs) in the past. In
Minnesota, we have completed remediation on two sites, other than ongoing
monitoring and water treatment. There are five remaining sites in our Minnesota
service territory. We believe that we have no liability with respect to two of
these sites.
At
December 31, 2008, we 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. We have utilized an environmental expense tracker
mechanism in our rates in Minnesota to recover estimated costs in excess of
insurance recovery. As of December 31, 2008, we had collected
$13 million from insurance companies and rate payers to be used for future
environmental remediation.
In
addition to the Minnesota sites, the EPA and other regulators have investigated
MGP sites that were owned or operated by us or may have been owned by one of our
former affiliates. We have 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 ours or our
divisions. We have 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 is required to determine
if other potentially responsible parties, including us, would have to contribute
to that remediation. We are investigating details regarding the site and the
range of environmental expenditures for potential remediation. However, we
believe we are not liable as a former owner or operator of the site under
CERCLA, and applicable state statutes, and are vigorously contesting the suit
and our designation as a PRP.
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 formerly owned by our predecessors have contained asbestos insulation
and other asbestos-containing materials. We or our predecessor companies have
been named, along with numerous others, as a defendant in lawsuits filed by
certain individuals who claim injury due to exposure to asbestos during work at
such
10
formerly
owned facilities. We anticipate that additional claims like those received may
be asserted in the future. 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 ours, 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 ours held an interest in two oil and gas leases on a portion of
the property at issue, neither it nor any other entities of ours drilled or
conducted other oil and gas operations on those leases. In January 2009,
we and the plaintiffs reached agreement on the terms of a settlement that, if
ultimately approved by the Louisiana Department of Natural Resources and the
court, is expected to finally resolve this litigation. We do not expect
the outcome of this litigation to have a material adverse impact on our
financial condition, results of operations or cash flows.
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, 2008, we had 4,643 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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Natural
Gas Distribution
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3,652 | 1,405 | ||||||
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Competitive
Natural Gas Sales and Services
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122 | — | ||||||
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Interstate
Pipelines
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654 | — | ||||||
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Field
Services
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215 | — | ||||||
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Total
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4,643 | 1,405 | ||||||
As of
December 31, 2008, approximately 30% of our employees are subject to
collective bargaining agreements. One of the collective bargaining agreements
covering approximately 9% of our employees, Gas Workers Union Local No. 340, is
scheduled to expire in 2009. We have a good relationship with this bargaining
unit and expect to negotiate a new agreement in 2009.
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 our business.
Risk
Factors Affecting Our Businesses
Rate regulation
of our business may delay or deny our ability to earn a reasonable return
and fully recover our costs.
Rates for
Gas Operations are regulated by certain municipalities and state commissions,
and for our interstate pipelines by the FERC, based on an analysis of our
invested capital and our expenses in a test year. Thus, the rates that we are
allowed to charge may not match our expenses at any given time. The regulatory
process in which rates
11
are
determined may not always result in rates that will produce full recovery of our
costs and enable us to earn a reasonable return on our invested
capital.
Our businesses
must compete with alternate energy sources, which could result in our marketing less
natural gas, and our 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 our results
of
operations, financial condition and cash flows.
We
compete 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 us 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 our 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 us as a result of competition may
have an adverse impact on our results of operations, financial condition and
cash flows.
Our two
interstate pipelines and our 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. We also compete indirectly with
other forms of energy, including electricity, coal and fuel oils. The primary
competitive factor is price. The actions of our competitors could lead to lower
prices, which may have an adverse impact on our 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 our results of
operations, financial condition and cash flows.
Our 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 our suppliers and customers to meet their obligations or otherwise
adversely affect our liquidity and results of operations.
We are
subject to risk associated with increases in the price of natural gas. Increases
in natural gas prices might affect our ability to collect balances due from our
customers and, for Gas Operations, could create the potential for uncollectible
accounts expense to exceed the recoverable levels built into our 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 we
operate thereby resulting in decreased sales volumes and revenues and
(ii) increase the risk that our suppliers or customers fail or are unable
to meet their obligations. Additionally, increasing natural gas prices could
create the need for us to provide collateral in order to purchase natural
gas.
A decline in our
credit rating could result in us having to provide collateral in order to
purchase gas.
If our
credit rating were to decline, we might be required to post cash collateral in
order to purchase natural gas. If a credit rating downgrade and the resultant
cash collateral requirement were to occur at a time when we were experiencing
significant working capital requirements or otherwise lacked liquidity, our
results of operations, financial condition and cash flows could be adversely
affected.
The revenues and
results of operations of our interstate pipelines and field services
businesses are subject to fluctuations in the supply and price of natural
gas.
Our
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 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
12
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 our results of
operations, financial condition and cash flows.
Our
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.
Our
revenues and results of operations are seasonal.
A
substantial portion of our revenues is derived from natural gas sales and
transportation. Thus, our 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 and related compression facilities may be
significantly higher than we had planned.
Our
subsidiaries 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 projects in the future.
The construction of new pipelines and related compression facilities requires
the expenditure of significant amounts of capital, which may exceed our
estimates. These projects may not be completed at the planned cost, on schedule
or at all. The construction of new pipeline 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 our expected investment return, which could adversely affect our
financial condition, results of operations or cash flows.
The states in
which we provide 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
our ability
to operate.
The
Public Utility Holding Company Act of 1935, to which CenterPoint Energy and its
subsidiaries were subject prior to its repeal in the Energy Act, 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 we do 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 businesses 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 our ability to operate our
utility operations, to finance our business and to provide cost-effective
utility service. In addition, if more than one state adopts restrictions over
similar activities, it may be difficult for us to comply with competing
regulatory requirements.
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, 2008, we had $3.9 billion of outstanding indebtedness on a
consolidated basis. As of December 31, 2008, approximately
$723 million principal amount of this debt is required to be paid through
2011. Our future financing activities may be significantly affected by, among
other things:
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general
economic and capital market
conditions;
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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 and CenterPoint Energy’s ability to access capital
markets on reasonable terms; and
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•
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provisions
of relevant tax and securities
laws.
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Our
current credit ratings are discussed in “Management’s Narrative Analysis of
Results of Operations — Liquidity — Impact on Liquidity of a Downgrade in Credit
Ratings” in Item 7 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.
The
financial condition and liquidity of our parent company could affect our access
to capital, our credit standing and our financial condition.
Our
access to credit and credit ratings may be impacted by CenterPoint Energy’s
credit standing. As of December 31, 2008, CenterPoint Energy and its
subsidiaries other than us have approximately $230 million principal amount
of debt required to be paid through 2011. This amount excludes amounts related
to capital leases, transition bonds and indexed debt securities obligations. We
cannot assure you that CenterPoint Energy and its other subsidiaries will be
able to pay or refinance these amounts. If CenterPoint Energy were to experience
a deterioration in its credit standing or liquidity difficulties, our access to
credit and our credit ratings could be adversely affected.
We
are an indirect wholly owned subsidiary of CenterPoint Energy. CenterPoint
Energy can exercise substantial control over our dividend policy and business
and operations and could do so in a manner that is adverse to our
interests.
We are
managed by officers and employees of CenterPoint Energy. Our management will
make determinations with respect to the following:
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our
payment of dividends;
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decisions
on our financings and our capital raising
activities;
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•
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mergers
or other business combinations; and
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our
acquisition or disposition of
assets.
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There are
no contractual restrictions on our ability to pay dividends to CenterPoint
Energy. Our management could decide to increase our dividends to CenterPoint
Energy to support its cash needs. This could adversely affect our liquidity.
However, under our credit facility and our receivables facility, our ability to
pay dividends is restricted by a covenant that debt as a percentage of total
capitalization may not exceed 65%.
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.
We
derive a substantial portion of our operating income from subsidiaries through
which we hold a substantial portion of our assets.
We derive
a substantial portion of our operating income from, and hold a substantial
portion of our assets through, our subsidiaries. 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.
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 described in “Business — Environmental
Matters” in Item 1 of this Form 10-K. As an owner or operator of
natural gas pipelines and distribution systems, and gas gathering and processing
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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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.
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In order
to comply with these requirements, we may need to spend substantial amounts and
devote other resources from time to time to:
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•
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construct
or acquire new equipment;
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acquire
permits for facility operations;
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•
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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.
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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.
We and
CenterPoint Energy could incur liabilities associated with businesses
and assets
that we have transferred to others.
Under
some circumstances, we and CenterPoint Energy could incur liabilities associated
with assets and businesses we and CenterPoint Energy no longer own.
In
connection with the organization and capitalization of Reliant Resources, Inc.
(RRI), RRI and its subsidiaries assumed liabilities associated with various
assets and businesses Reliant Energy, Incorporated (Reliant Energy) transferred
to them. RRI also agreed to indemnify, and cause the applicable
transferee subsidiaries to indemnify, CenterPoint Energy and its subsidiaries,
including us, 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 and CenterPoint Energy could be responsible for satisfying
the liability.
Prior to
CenterPoint Energy’s distribution of its ownership in RRI to its shareholders,
we had guaranteed certain contractual obligations of what became RRI’s trading
subsidiary. Under the terms of the separation agreement between the companies,
RRI agreed to extinguish all such guaranty obligations prior to separation, but
at the time of separation in September 2002, RRI had been unable to extinguish
all obligations. To secure us against obligations under the remaining
guaranties, RRI agreed to provide cash or letters of credit for our benefit, and
undertook to use commercially reasonable efforts to extinguish the remaining
guaranties. In December 2007, we, CenterPoint Energy and RRI amended
that agreement and we released the letters of credit we held as
security. Under the revised agreement, RRI agreed to provide cash or
new letters of credit to secure us against exposure under the remaining
guaranties as calculated under the revised agreement if and to the extent
changes in market conditions exposed us to a risk of loss on those
guaranties.
Our
potential exposure under the guaranties relates to payment of demand charges
related to transportation contracts. The present value of the demand charges
under these transportation contracts, which will be effective until 2018, was
approximately $108 million as of December 31, 2008. RRI continues to meet
its obligations under the contracts, and on the basis of market conditions, we
and CenterPoint Energy have not required additional security. However, if RRI
should fail to perform its obligations under the contracts or if RRI should fail
to provide adequate security in the event market conditions change adversely, we
would retain our exposure to the counterparty under the guaranty.
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.
CenterPoint
Energy, Reliant Energy, RRI and one of our subsidiaries are named as defendants
in a number of lawsuits arising out of the operations of the natural gas markets
in 2000-2001. Although these matters relate to the business and operations of
RRI, we or CenterPoint Energy could incur liability if claims in one or more of
these lawsuits were successfully asserted against us, any of our subsidiaries or
CenterPoint Energy and indemnification from RRI were determined to be
unavailable or if RRI were unable to satisfy indemnification obligations owed
with respect to those claims.
The global
financial crisis may have impacts on our business, liquidity and financial
condition that we currently
cannot predict.
The
continued credit crisis and related turmoil 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 may be materially adversely
impacted by these market conditions. With respect to our existing debt
arrangements, Lehman Brothers Bank, FSB, which had an approximately four percent
participation in our credit facility, stopped funding its commitment following
the bankruptcy filing of its parent in September 2008. Defaults of other
lenders, should they 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 CenterPoint Energy’s
pension plan in which we participate. These reductions are expected to result in
increased pension expense in 2009, which will impact 2009 results of
operations.
In
addition to the credit and financial market issues, the 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.
Not
applicable.
Item
2. Properties
Character
of Ownership
We own
our principal properties in fee. Most of our gas mains are located, pursuant to
easements and other rights, on public roads or on land owned by
others.
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.
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 9(d) to our consolidated financial statements, which
information is incorporated herein by reference.
Item
4. Submission of
Matters to a Vote of Security Holders
The
information called for by Item 4 is omitted pursuant to Instruction I(2) to Form
10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
PART II
Item
5. Market for
Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
All of
the 1,000 outstanding shares of CERC Corp.’s common stock are held by Utility
Holding, LLC, a wholly owned subsidiary of CenterPoint Energy.
In each
of 2006, 2007 and 2008, we paid dividends on our common stock of
$100 million to Utility Holding, LLC.
Our
revolving credit facility limits our debt as a percentage of total
capitalization to 65%. This covenant could restrict our ability to
distribute dividends.
Item
6. Selected
Financial Data
The
information called for by Item 6 is omitted pursuant to Instruction I(2) to Form
10-K (Omission of Information by Certain Wholly Owned
Subsidiaries). The ratio of earnings to fixed charges as calculated
pursuant to Securities and Exchange Commission rules was 2.20, 2.64, 2.67, 3.10
and 3.32 for the years ended December 31, 2004, 2005, 2006, 2007 and 2008,
respectively.
The
following narrative analysis should be read in combination with our consolidated
financial statements and notes contained in Item 8 of this report.
Background
We own
and operate natural gas distribution systems in six states. Subsidiaries of ours
own interstate natural gas pipelines and gas gathering systems and provide
various ancillary services. A wholly owned subsidiary of ours offers variable
and fixed-price physical natural gas supplies primarily to commercial and
industrial customers and electric and gas utilities. We are an indirect wholly
owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy).
Business
Segments
Because
we are an indirect wholly owned subsidiary of CenterPoint Energy, our
determination of reportable 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. In this section, we discuss our results on a
consolidated basis and individually for each of our business segments. We also
discuss our liquidity, capital resources and critical accounting policies. 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 natural gas distribution services and interstate
pipelines are subject to rate regulation. A summary of our reportable business
segments as of December 31, 2008 is set forth below:
Natural
Gas Distribution
We own
and operate 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
Our
operations also include non-rate regulated retail and wholesale natural gas
sales to, and transportation services for, commercial and industrial customers
in the six states listed above as well as several other Midwestern and Eastern
states.
Interstate
Pipelines
Our
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. We also own and operate 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. We also own 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. Our storage capacity in
the Bistineau facility is 8 Bcf of working gas with 100 million cubic
feet per day of deliverability. Most storage operations are in north Louisiana
and Oklahoma.
Field
Services
Our field
services business owns and operates approximately 3,600 miles of gathering
pipelines and processing plants that collect, treat and process natural gas from
approximately 150 separate systems located in major producing fields in
Arkansas, Louisiana, Oklahoma and Texas.
Other
Operations
Our other
operations business segment includes unallocated corporate costs and
inter-segment eliminations.
EXECUTIVE
SUMMARY
Significant
Events in 2008 and 2009
Hurricane
Ike
Gas
Operations 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, which struck the upper Texas coast in September 2008. As of
December 31, 2008, Gas Operations has deferred approximately
$4 million of costs related to Hurricane Ike for recovery as part of future
natural gas distribution rate proceedings.
Debt
Financing Transactions
In May
2008, we issued $300 million aggregate principal amount of senior notes due
in May 2018 with an interest rate of 6.00%. The proceeds from the sale of the
senior notes were used for general corporate purposes, including capital
expenditures, working capital and loans to or investments in
affiliates.
In
November 2008, we replaced a receivables facility that had expired in October
2008 with a new receivables facility that expires in November 2009. Availability
under the new facility ranges from $128 million to $375 million,
reflecting seasonal changes in receivables balances.
In
December 2008, we entered into an asset management agreement whereby we sold
$110 million of our 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, as of December 31, 2008, the consolidated financial
statements reflect natural gas inventory of $75 million and a financing
obligation of $75 million related to this transaction.
Interstate
Pipeline Expansion
The
Southeast Supply Header (SESH) pipeline project, a joint venture between
CenterPoint Energy Gas Transmission, our wholly owned subsidiary, and Spectra
Energy Corp., was placed into commercial service on September 6, 2008.
This new 270-mile pipeline, which extends from the Perryville
Hub, near Perryville, Louisiana, to an interconnection with the Gulf Stream
Natural Gas System near Mobile, Alabama, has a maximum design capacity of
approximately one Bcf per day. The pipeline represents a new source of
natural gas supply for the Southeast United States and offers greater supply
diversity to this region. Our share of SESH’s net construction costs is
approximately $625 million.
Outlook
During
2008, economic conditions in the United States declined significantly, with
several large bank failures and consolidations, large declines in the values of
securities, disruptions in the capital markets, which made it difficult to raise
debt and equity, and increased costs for capital when it was available.
Many of the factors that led to the economic decline are continuing into 2009,
but it is impossible to predict the impacts such events may have in the
future. Although our businesses and the areas in which we serve have, to
date, not been as significantly affected as some others, in 2008, CenterPoint
Energy experienced substantial declines in the value of the assets of its
pension plan, in which we participate, as a result of the stock market
declines. Disruptions in the bank and capital markets during the last two
quarters of 2008 have led to higher borrowing costs and greater uncertainty
regarding the ability to execute transactions in these markets.
Although
we cannot predict future performance, the decline in the value of CenterPoint
Energy’s pension plan assets that occurred during 2008 will result in increased
charges to pension plan expense in 2009, which will adversely impact earnings,
and may also result in the need for CenterPoint Energy to make significant cash
contributions to its pension plan subsequent to 2009. We also expect
to experience higher borrowing costs and greater uncertainty in executing
capital markets transactions if conditions in financial markets do not improve
from their current state.
To the
extent the adverse economic conditions affect our suppliers and customers,
results from our energy delivery businesses may suffer. The current low
commodity prices for natural gas and other energy products may cause energy
producers to scale back projects such as drilling new gas wells or constructing
new facilities. 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.
These factors may lead to reduced earnings during 2009, compared to 2008, if
they continue significantly into 2009 or if the magnitude of the economic
downturn increases beyond the impacts experienced in 2008.
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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state
and federal legislative and regulatory actions or developments, including
deregulation, re-regulation, environmental regulations,
including regulations related to global climate change, and changes in or
application of laws or regulations applicable to the various aspects of
our business;
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timely
and appropriate rate actions and increases, allowing recovery of costs,
including those associated with Hurricane Ike, and a reasonable return on
investment;
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cost
overruns on major capital projects that cannot be recouped in
prices;
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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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the
timing and extent of changes in commodity prices, particularly natural gas
and natural gas liquids;
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the
timing and extent of changes in the supply of natural
gas;
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the
timing and extent of changes in natural gas basis
differentials;
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weather
variations and other natural
phenomena;
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changes
in interest rates or rates of
inflation;
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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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actions
by rating agencies;
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effectiveness
of our risk management activities;
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inability
of various counterparties to meet their obligations to
us;
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non-payment
for our services due to financial distress of our
customers;
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the
ability of Reliant Energy, Inc. (RRI) to satisfy its obligations to us in
connection with the contractual arrangements pursuant to which we are
their guarantor;
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the
outcome of litigation brought by or against
us;
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our
ability to control costs;
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the
investment performance of CenterPoint Energy’s employee benefit
plans;
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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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acquisitions
and merger activities involving us or our competitors;
and
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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
Our
results of operations are affected by seasonal fluctuations in the demand for
natural gas and price movements of energy commodities as well as natural gas
basis differentials. Our results of operations are also affected by,
among other things, the actions of various federal and state governmental
authorities having jurisdiction over rates we charge, competition in our various
business operations, debt service costs and income tax expense.
The
following table sets forth selected financial data (in millions) for the years
ended December 31, 2006, 2007 and 2008, followed by a discussion of our
consolidated results of operations based on operating income. We have
provided a reconciliation of consolidated operating income to net income
below.
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Year
Ended December 31,
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2006
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2007
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2008
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||||||||||
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Revenues
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$ | 7,528 | $ | 7,776 | $ | 9,395 | ||||||
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Expenses:
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Natural
gas
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5,909 | 5,995 | 7,466 | |||||||||
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Operation
and maintenance
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798 | 800 | 828 | |||||||||
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Depreciation
and amortization
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200 | 215 | 218 | |||||||||
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Taxes
other than income taxes
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149 | 140 | 166 | |||||||||
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Total
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7,056 | 7,150 | 8,678 | |||||||||
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Operating
Income
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472 | 626 | 717 | |||||||||
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Interest
and other finance charges
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(167 | ) | (187 | ) | (206 | ) | ||||||
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Equity
in earnings of unconsolidated affiliates
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6 | 16 | 51 | |||||||||
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Other
income, net
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12 | 5 | 9 | |||||||||
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Income
Before Income Taxes
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323 | 460 | 571 | |||||||||
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Income
Tax Expense
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(116 | ) | (173 | ) | (228 | ) | ||||||
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Net
Income
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$ | 207 | $ | 287 | $ | 343 | ||||||
2008 Compared to
2007. We reported net income of $343 million for 2008 as
compared to $287 million for 2007. The increase in net income of
$56 million was primarily due to a $91 million increase in operating
income from our business segments as discussed below and a $35 million
increase in equity in earnings of unconsolidated affiliates related primarily to
SESH, partially offset by a $55 million increase in income tax expense due
to higher earnings and a $19 million increase in interest
expense.
Our
effective tax rate for 2008 and 2007 was 40.0% and 37.6%,
respectively.
2007 Compared to
2006. We reported net income of $287 million for 2008 as
compared to $207 million for 2007. The increase in net income of
$80 million was primarily due to a $154 million increase in operating
income from our business segments as discussed below, partially offset by a
$57 million increase in income tax expense due to higher earnings and a
$20 million increase in interest expense.
Our
effective tax rate for 2007 and 2006 was 37.6% and 36.1%,
respectively.
RESULTS
OF OPERATIONS BY BUSINESS SEGMENT
The
following table presents operating income (in millions) for each of our business
segments for 2006, 2007 and 2008. Included in revenues are intersegment sales.
We account for intersegment sales as if the sales were to third parties, that
is, at current market prices.
Operating
Income (Loss) by Business Segment
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Year
Ended December 31,
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2006
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2007
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2008
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Natural
Gas Distribution
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$ | 124 | $ | 218 | $ | 215 | ||||||
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Competitive
Natural Gas Sales and Services
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77 | 75 | 62 | |||||||||
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Interstate
Pipelines
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181 | 237 | 293 | |||||||||
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Field
Services
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89 | 99 | 147 | |||||||||
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Other
Operations
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1 | (3 | ) | — | ||||||||
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Total
Consolidated Operating Income
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$ | 472 | $ | 626 | $ | 717 | ||||||
Natural
Gas Distribution
The
following table provides summary data of our Natural Gas Distribution business
segment for 2006, 2007 and 2008 (in millions, except throughput and customer
data):
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Year
Ended December 31,
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2006
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2007
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2008
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||||||||||
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Revenues
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$ | 3,593 | $ | 3,759 | $ | 4,226 | ||||||
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Expenses:
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Natural
gas
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2,598 | 2,683 | 3,124 | |||||||||
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Operation
and maintenance
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594 | 579 | 589 | |||||||||
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Depreciation
and amortization
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152 | 155 | 157 | |||||||||
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Taxes
other than income taxes
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125 | 124 | 141 | |||||||||
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Total
expenses
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3,469 | 3,541 | 4,011 | |||||||||
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Operating
Income
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$ | 124 | $ | 218 | $ | 215 | ||||||
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Throughput
(in Bcf):
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Residential
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152 | 172 | 175 | |||||||||
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Commercial
and industrial
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224 | 232 | 236 | |||||||||
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Total
Throughput
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376 | 404 | 411 | |||||||||
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Number
of customers at period end:
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Residential
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2,926,483 | 2,961,110 | 2,987,222 | |||||||||
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Commercial
and industrial
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246,351 | 249,877 | 248,476 | |||||||||
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Total
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3,172,834 | 3,210,987 | 3,235,698 | |||||||||
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 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).
2007 Compared to
2006. Our Natural Gas Distribution business segment reported
operating income of $218 million for 2007 compared to $124 million for
2006. Operating income improved as a result of increased usage primarily due to
a return to more normal weather in 2007 compared to the unusually mild weather
in 2006 ($33 million), growth from the addition of over 38,000 customers in
2007 ($9 million), the effect of the 2006 purchased gas cost write-off
($21 million), the effect of rate changes ($7 million) and reduced
operation and maintenance expenses ($15 million). Operation and maintenance
expenses declined primarily as a result of costs associated with staff
reductions incurred in 2006 ($17 million) and settlement of certain rate
case-related items
23
($9 million),
partially offset by increases in bad debts and collection costs
($8 million) and other services ($5 million).
Competitive
Natural Gas Sales and Services
The
following table provides summary data of our Competitive Natural Gas Sales and
Services business segment for 2006, 2007 and 2008 (in millions, except
throughput and customer data):
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Year
Ended December 31,
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2006
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2007
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2008
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Revenues
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$ | 3,651 | $ | 3,579 | $ | 4,528 | ||||||
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Expenses:
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Natural
gas
|
3,540 | 3,467 | 4,423 | |||||||||
|
Operation
and maintenance
|
30 | 31 | 39 | |||||||||
|
Depreciation
and amortization
|
1 | 5 | 3 | |||||||||
|
Taxes
other than income taxes
|
3 | 1 | 1 | |||||||||
|
Total
expenses
|
3,574 | 3,504 | 4,466 | |||||||||
|
Operating
Income
|
$ | 77 | $ | 75 | $ | 62 | ||||||
|
Throughput
(in Bcf)
|
555 | 522 | 528 | |||||||||
|
Number
of customers at period end
|
7,024 | 7,139 | 9,771 | |||||||||
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 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. 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.
2007 Compared to
2006. Our Competitive Natural Gas Sales and Services business
segment reported operating income of $75 million for 2007 compared to
$77 million for 2006. The decrease in operating income of $2 million
was primarily due to reduced opportunities for optimization of pipeline and
storage assets resulting from lower locational and seasonal natural gas price
differentials in the wholesale business ($10 million) offset by an increase
in sales to commercial and industrial customers in the retail business
($3 million). In addition, 2007 included 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), compared to a gain from mark-to-market accounting
($37 million) and an inventory write-down ($66 million) for
2006.
Interstate
Pipelines
The
following table provides summary data of our Interstate Pipelines business
segment for 2006, 2007 and 2008 (in millions, except throughput
data):
|
Year
Ended December 31,
|
||||||||||||
|
2006
|
2007
|
2008
|
||||||||||
|
Revenues
|
$ | 388 | $ | 500 | $ | 650 | ||||||
|
Expenses:
|
||||||||||||
|
Natural
gas
|
31 | 83 | 155 | |||||||||
|
Operation
and maintenance
|
120 | 125 | 133 | |||||||||
|
Depreciation
and amortization
|
37 | 44 | 46 | |||||||||
|
Taxes
other than income taxes
|
19 | 11 | 23 | |||||||||
|
Total
expenses
|
207 | 263 | 357 | |||||||||
|
Operating
Income
|
$ | 181 | $ | 237 | $ | 293 | ||||||
|
Transportation
throughput (in Bcf)
|
939 | 1,216 | 1,538 | |||||||||
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 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 are 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.
2007 Compared to
2006. Our Interstate Pipeline business segment reported
operating income of $237 million for 2007 compared to $181 million for
2006. The increase in operating income of $56 million was driven primarily
by the new Carthage to Perryville pipeline ($42 million), other
transportation and ancillary services ($20 million), lower spending in 2007
on project development costs ($6 million) and a decrease in other taxes
($8 million) related to the settlement of certain state tax issues. These
favorable variances to operating income were partially offset by lower sales in
2007 of excess gas associated with storage enhancement projects
($15 million) and increased operating expenses
($6 million).
Equity Earnings. In addition,
this business segment recorded equity income of $6 million and
$36 million (including $6 million and $33 million of
pre-operating allowance for funds used during construction) in the years ended
December 31, 2007 and 2008, respectively, from its 50 percent interest in
SESH, a jointly-owned pipeline. 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
2006, 2007 and 2008 (in millions, except throughput data):
|
Year
Ended December 31,
|
||||||||||||
|
2006
|
2007
|
2008
|
||||||||||
|
Revenues
|
$ | 150 | $ | 175 | $ | 252 | ||||||
|
Expenses:
|
||||||||||||
|
Natural
gas
|
(10 | ) | (4 | ) | 21 | |||||||
|
Operation
and maintenance
|
59 | 66 | 69 | |||||||||
|
Depreciation
and amortization
|
10 | 11 | 12 | |||||||||
|
Taxes
other than income taxes
|
2 | 3 | 3 | |||||||||
|
Total
expenses
|
61 | 76 | 105 | |||||||||
|
Operating
Income
|
$ | 89 | $ | 99 | $ | 147 | ||||||
|
Gathering
throughput (in Bcf)
|
375 | 398 | 421 | |||||||||
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
($7 million).
2007 Compared to
2006. Our Field Services business segment reported operating
income of $99 million for 2007 compared to $89 million for 2006.
Continued increased demand for gas gathering and ancillary services
($27 million) was partially offset by lower commodity prices
($10 million) and increased operation and maintenance expenses related to
cost increases and expanded operations ($7 million).
Equity Earnings. In addition,
this business segment recorded equity income of $6 million,
$10 million and $15 million for the years ended December 31,
2006, 2007 and 2008, respectively, from its 50 percent 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.
Fluctuations
in Commodity Prices and Derivative Instruments
For
information regarding our exposure to risk as a result of fluctuations in
commodity prices and derivative instruments, please read “Quantitative and
Qualitative Disclosures About Market Risk” in Item 7A of this
report.
LIQUIDITY
Our
liquidity and capital requirements are affected primarily by our results of
operations, capital expenditures, debt service requirements, tax payments and
working capital needs. Our principal anticipated cash requirements for 2009
include approximately $637 million of capital expenditures and maturing
long-term debt aggregating approximately $7 million.
We expect
that borrowings under our credit facilities, anticipated cash flows from
operations and intercompany borrowings will be sufficient to meet our
anticipated cash needs in 2009. Cash needs or discretionary financing or
refinancing may result in the issuance of debt securities in the capital markets
or the arrangement of additional credit facilities. Issuances of 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 2008 and estimates of
our capital requirements for 2009 through 2013 (in millions):
|
2008
|
2009
|
2010
|
2011
|
2012
|
2013
|
|||||||||||||||||||
|
Natural
Gas Distribution
|
$ | 214 | $ | 155 | $ | 234 | $ | 241 | $ | 243 | $ | 249 | ||||||||||||
|
Competitive
Natural Gas Sales and Services
|
8 | 3 | 3 | 3 | 3 | 3 | ||||||||||||||||||
|
Interstate
Pipelines
|
189 | 202 | 151 | 87 | 67 | 70 | ||||||||||||||||||
|
Field
Services
|
122 | 277 | 142 | 82 | 93 | 85 | ||||||||||||||||||
|
Total
|
$ | 533 | $ | 637 | $ | 530 | $ | 413 | $ | 406 | $ | 407 | ||||||||||||
The
following table sets forth estimates of our contractual obligations, including
payments due by period (in millions):
|
Contractual
Obligations
|
Total
|
2009
|
2010-2011 | 2012-2013 |
2014
and
thereafter
|
|||||||||||||||
|
Long-term
debt
|
$ | 3,719 | $ | 7 | $ | 563 | $ | 1,722 | $ | 1,427 | ||||||||||
|
Interest
payments — long-term debt(1)
|
1,693 | 209 | 394 | 275 | 815 | |||||||||||||||
|
Short-term
borrowings
|
153 | 153 | — | — | — | |||||||||||||||
|
Operating
leases(2)
|
74 | 14 | 22 | 13 | 25 | |||||||||||||||
|
Benefit
obligations(3)
|
— | — | — | — | — | |||||||||||||||
|
Purchase
obligations(4)
|
24 | 24 | — | — | — | |||||||||||||||
|
Non-trading
derivative liabilities
|
134 | 87 | 41 | 6 | — | |||||||||||||||
|
Other
commodity commitments(5)
|
3,520 | 776 | 911 | 877 | 956 | |||||||||||||||
|
Income
taxes(6)
|
— | — | — | — | — | |||||||||||||||
|
Total
contractual cash obligations
|
$ | 9,317 | $ | 1,270 | $ | 1,931 | $ | 2,893 | $ | 3,223 | ||||||||||
__________
|
(1)
|
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, 2008. We
typically expect to settle such interest payments with cash flows from
operations and short-term
borrowings.
|
|
(2)
|
For
a discussion of operating leases, please read Note 9(b) to our
consolidated financial
statements.
|
|
(3)
|
We
expect to contribute approximately $9 million to our postretirement
benefits plan in 2009 to fund a portion of our obligations in accordance
with rate orders or to fund pay-as-you-go costs associated with the
plan.
|
|
(4)
|
Represents
capital commitments for material in connection with the construction of a
pipeline by our Interstate Pipelines business segment. This project has
been included in the table of capital expenditures presented
above.
|
|
(5)
|
For
a discussion of other commodity commitments, please read Note 9(a) to our
consolidated financial
statements.
|
|
(6)
|
As
of December 31, 2008, we had a receivable for uncertain tax positions of
$12 million.
|
Off-Balance Sheet
Arrangements. Other than operating leases and the guaranties
described below, we have no off-balance sheet arrangements.
Prior to
CenterPoint Energy’s distribution of its ownership in RRI to its shareholders,
we had guaranteed certain contractual obligations of what became RRI’s trading
subsidiary. Under the terms of the separation agreement between the companies,
RRI agreed to extinguish all such guaranty obligations prior to separation, but
at the time of separation in September 2002, RRI had been unable to extinguish
all obligations. To secure us against obligations under the remaining
guaranties, RRI agreed to provide cash or letters of credit for our benefit, and
undertook to use commercially reasonable efforts to extinguish the remaining
guaranties. In December 2007, we, CenterPoint Energy and RRI amended
that agreement and we released the letters of credit we held as
security. Under the revised agreement, RRI agreed to provide cash or
new letters of credit to secure us against exposure under the
remaining
27
guaranties
as calculated under the revised agreement if and to the extent changes in market
conditions exposed us to a risk of loss on those guaranties.
Our
potential exposure under the guaranties relates to payment of demand charges
related to transportation contracts. The present value of the demand charges
under these transportation contracts, which will be effective until 2018, was
approximately $108 million as of December 31, 2008. RRI continues to meet
its obligations under the contracts, and on the basis of market conditions, we
and CenterPoint Energy have not required additional security. However, if RRI
should fail to perform its obligations under the contracts or if RRI should fail
to provide adequate security in the event market conditions change adversely, we
would retain our exposure to the counterparty under the guaranty.
Debt Financing
Transactions. In May 2008, we issued $300 million
aggregate principal amount of senior notes due in May 2018 with an interest
rate of 6.00%. The proceeds from the sale of the senior notes were used for
general corporate purposes, including capital expenditures, working capital and
loans to or investments in affiliates.
In
December 2008, we entered into an asset management agreement whereby we sold
$110 million of our 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, as of December 31, 2008, the consolidated financial
statements reflect natural gas inventory of $75 million and a financing
obligation of $75 million related to this transaction.
Credit and Receivables
Facilities. Our $950 million credit facility’s first drawn
cost is the London Interbank Offered Rate (LIBOR) plus 45 basis points
based on our current credit ratings. The facility contains covenants,
including a debt to total capitalization covenant.
Under the
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 our credit rating. Borrowings
under the facility are subject to customary terms and conditions. However, there
is no requirement that we 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 the credit facility are subject to
acceleration upon the occurrence of events of default that we consider
customary.
In November 2008, we replaced a receivables facility that had expired in October
2008 with a new receivables facility that expires in November 2009. Availability
under the new facility ranges from $128 million to $375 million,
reflecting seasonal changes in receivables balances.
We are
currently in compliance with the various business and financial covenants
contained in the respective receivables and credit facilities.
As of
February 13, 2009, we had the following facilities (in millions):
|
Date
Executed
|
Company
|
Type
of Facility
|
Size
of Facility
|
Amount
Utilized at
February
13, 2009
|
Termination
Date
|
||||||||
|
June
29, 2007
|
CERC
Corp.
|
Revolver
|
$ | 950 | (1) | $ | 781 |
June
29, 2012
|
|||||
|
November
25, 2008
|
CERC
|
Receivables
|
375 | — |
November
24,
2009
|
||||||||
__________
|
(1)
|
Lehman
Brothers Bank, FSB, stopped funding its commitments following the
bankruptcy filing of its parent in September 2008, effectively causing a
reduction to the total available capacity of $20 million under our
facility.
|
Our
$950 million credit facility backstops a $915 million commercial paper
program under which we began issuing commercial paper in February 2008. Our
commercial paper is rated “P-3” by Moody’s Investors Service, Inc. (Moody’s),
“A-2” by Standard & Poor’s Rating Services (S&P), a division of The
McGraw-Hill Companies, and “F2” by Fitch, Inc. (Fitch). As a result
of the credit ratings on our commercial paper program, 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
28
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. At December 31, 2008, we had a shelf registration
statement covering $500 million principal amount of senior debt
securities.
Temporary
Investments. As of February 13, 2009, we had no external
temporary investments.
Money Pool. We
participate in a money pool through which we and certain of our affiliates 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 CenterPoint Energy’s revolving credit facility or the sale of CenterPoint
Energy’s commercial paper. At February 13, 2009, we had no borrowings from the
money pool. The money pool may not provide sufficient funds to meet
our cash needs.
Impact on Liquidity of a Downgrade
in Credit Ratings. As of February 13, 2009, Moody’s,
S&P and Fitch had assigned the following credit ratings to our senior
unsecured debt:
|
Moody’s
|
S&P
|
Fitch
|
||||||||||
|
Company/Instrument
|
Rating
|
Outlook(1)
|
Rating
|
Outlook(2)
|
Rating
|
Outlook(3)
|
||||||
|
CERC
Corp. Senior Unsecured Debt
|
Baa3
|
Stable
|
BBB
|
Stable
|
BBB
|
Stable
|
||||||
__________
|
(1)
|
A
“stable” outlook from Moody’s indicates that Moody’s does not expect to
put the rating on review for an upgrade or downgrade within 18 months from
when the outlook was assigned or last
affirmed.
|
|
(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 these credit ratings could increase borrowing costs under our
$950 million credit facility. 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.
Additionally, a decline in credit ratings could increase cash collateral
requirements and reduce earnings of our Natural Gas Distribution and Competitive
Natural Gas Sales and Services business segments.
CenterPoint
Energy Services, Inc. (CES), our wholly owned subsidiary 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, 2008, the amount posted as collateral aggregated approximately
$229 million. Should our credit ratings (as the credit support provider for
CES) fall below certain levels, CES would be required to provide additional
collateral on two business days’ notice up to the amount of its previously
unsecured credit limit. We estimate that as of December 31, 2008, unsecured
credit limits extended to CES by counterparties aggregate $250 million;
however, utilized credit capacity is significantly lower. In addition, we and
our subsidiaries purchase natural gas under supply agreements that contain an
aggregate credit threshold of $100 million based on our S&P Senior
Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB
rating will increase and decrease the aggregate credit threshold
accordingly.
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 our credit ratings decline below the applicable threshold
levels, we might need to provide cash or other collateral of as much as
$160 million, the amount depending on seasonal variations in transportation
levels.
Cross Defaults. Under
CenterPoint Energy’s revolving credit facility, a payment default on, or a
non-payment default that permits acceleration of, any indebtedness exceeding
$50 million by us will cause a default. In addition, four outstanding
series of CenterPoint Energy’s senior notes, aggregating $950 million in
principal amount as of February 13, 2009, provide that a payment default by us
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 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, particularly given gas price
levels and volatility;
|
|
|
•
|
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 indemnification
obligations to us or in connection with the contractual arrangement
pursuant to which we are a
guarantor;
|
|
|
•
|
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;
|
|
|
•
|
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. Our bank facility and our
receivables facility limit our debt as a percentage of our total capitalization
to 65%.
Relationship with CenterPoint
Energy. We are an indirect wholly owned subsidiary of CenterPoint Energy.
As a result of this relationship, the financial condition and liquidity of our
parent company could affect our access to capital, our credit standing and our
financial condition.
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 of CenterPoint Energy.
Accounting
for Rate Regulation
Statement
of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of
Certain Types of Regulation” (SFAS No. 71), 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
Natural Gas Distribution business segment and portions of our Interstate
Pipelines business segment apply SFAS No. 71. 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, as defined in SFAS No. 5,
“Accounting for Contingencies” (SFAS No. 5), 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.
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 Statement of Financial Accounting Standards (SFAS) No. 142,
“Goodwill and Other Intangible Assets.” No impairment of goodwill was
indicated based on our annual analysis as of July 1, 2008. 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
31
measures.
The fair value of the asset could be different using different estimates and
assumptions in these valuation techniques.
Asset
Retirement Obligations
We
account for our long-lived assets under SFAS No. 143, “Accounting for Asset
Retirement Obligations” (SFAS No. 143), and Financial Accounting Standards
Board (FASB)
Interpretation No. (FIN) 47, “Accounting for Conditional Asset
Retirement Obligations - An Interpretation of SFAS No. 143” (FIN
47). SFAS No. 143 and FIN 47 require that an asset retirement
obligation be recorded at fair value in the period in which it is incurred if a
reasonable estimate of fair value can be made. In the same period, the
associated asset retirement costs are capitalized as part of the carrying amount
of the related long-lived asset. Rate-regulated entities may recognize
regulatory assets or liabilities as a result of timing differences between the
recognition of costs as recorded in accordance with SFAS No. 143 and FIN 47, and
costs recovered through the ratemaking process.
We
estimate the fair value of asset retirement obligations by calculating the
discounted cash flows that are dependent upon the following
components:
|
|
•
|
Inflation adjustment -
The estimated cash flows are adjusted for inflation estimates for labor,
equipment, materials, and other disposal
costs;
|
|
|
•
|
Discount rate - The
estimated cash flows include contingency factors that were used as a proxy
for the market risk premium; and
|
|
|
•
|
Third party markup
adjustments - Internal labor costs included in the cash flow
calculation were adjusted for costs that a third party would incur in
performing the tasks necessary to retire the
asset.
|
Changes
in these factors could materially affect the obligation recorded to reflect the
ultimate cost associated with retiring the assets under SFAS No. 143 and FIN 47.
For example, if the inflation adjustment increased 25 basis points, this
would increase the balance for asset retirement obligations by approximately 2%.
Similarly, an increase in the discount rate by 25 basis points would decrease
asset retirement obligations by approximately the same percentage. At
December 31, 2008, our estimated cost of retiring these assets was
approximately $46 million.
Unbilled
Energy Revenues
Revenues
related to 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 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.
NEW
ACCOUNTING PRONOUNCEMENTS
See Note
2(n) to the consolidated financial statements, incorporated herein by reference,
for a discussion of new accounting pronouncements that affect us.
OTHER
SIGNIFICANT MATTERS
Pension Plans. As discussed
in Note 2(o) to our consolidated financial statements, we participate in
CenterPoint Energy’s qualified and non-qualified pension plans covering
substantially all employees. The expected pension expense for 2009 is
$47 million, of which we expect $41 million to impact pre-tax earnings,
based on an expected return on plan assets of 8.00% and a discount rate of 6.90%
as of December 31, 2008. We recorded pension income of $2 million for
the year ended December 31, 2008. The increase in pension
expense in 2009 is primarily the result of a decline in 2008 in plan assets of
the CenterPoint Energy pension plan, in which we participate. Future
changes
32
in plan
asset returns, assumed discount rates and various other factors related to the
pension plans will impact our future pension expense. We cannot predict with
certainty what these factors will be in the future.
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.
Interest
Rate Risk
As of
December 31, 2008, we had outstanding long-term debt and bank loans from
affiliates that subject us to the risk of loss associated with movements in
market interest rates.
Our
floating-rate obligations aggregated $449 million and $1.0 billion at
December 31, 2007 and 2008, respectively. If the floating interest rates
were to increase by 10% from December 31, 2008 rates, our combined interest
expense would increase by approximately $2 million annually.
At both
December 31, 2007 and 2008, we had outstanding fixed-rate debt aggregating
$2.8 billion in principal amount and having a fair value of
$2.9 billion and $2.6 billion, respectively. These instruments are
fixed-rate and, therefore, do not expose us to the risk of loss in earnings due
to changes in market interest rates (please read Note 7 to our consolidated
financial statements). However, the fair value of these instruments would
increase by approximately $104 million if interest rates were to decline by 10%
from their levels at December 31, 2008. 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.
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, 2008, the recorded fair
value of our non-trading energy derivatives was a net liability of
$183 million (before collateral). The net liability consisted of a net
liability of $224 million associated with price stabilization activities of
our Natural Gas Distribution business segment and a net asset of
$41 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, 2008 levels would have
increased the fair value of our non-trading energy derivatives net liability by
$118 million with all of the increase attributable to price stabilization
activities related to our Natural Gas Distribution business
segment. There would be no consolidated income statement impact of
the $118 million as the Natural Gas Distribution segment records the offset
to net over/under recovered gas cost liabilities or assets on the balance
sheet.
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.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Stockholder of
CenterPoint
Energy Resources Corp.
Houston,
Texas
We have
audited the accompanying consolidated balance sheets of CenterPoint Energy
Resources Corp. and subsidiaries (the “Company”, an indirect wholly owned
subsidiary of CenterPoint Energy, Inc.) as of December 31, 2008 and 2007, and
the related statements of consolidated income, comprehensive income, cash flows
and stockholder’s equity for each of the three years in the period ended
December 31, 2008. 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. The Company is not
required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting. Our audits included consideration of
internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Company's internal control
over financial reporting. Accordingly, we express no such opinion.
An audit also includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, 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 Resources Corp. and subsidiaries at
December 31, 2008 and 2007, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2008, in
conformity with accounting principles generally accepted in the United States of
America.
DELOITTE
& TOUCHE LLP
Houston,
Texas
March 11,
2009
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, 2008.
This
annual report does not include an attestation report of our registered public
accounting firm regarding internal control over financial
reporting. Management’s report was not subject to attestation by our
registered public accounting firm pursuant to temporary rules of the Securities
and Exchange Commission that permit us to provide only management’s report in
this annual report.
|
/s/ DAVID
M. MCCLANAHAN
|
|
|
President
and Chief Executive Officer
|
|
|
/s/ GARY
L. WHITLOCK
|
|
|
Executive
Vice President and Chief
|
|
|
Financial
Officer
|
March 11,
2009
(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
STATEMENTS
OF CONSOLIDATED INCOME
|
Year
Ended December 31,
|
||||||||||||
|
2006
|
2007
|
2008
|
||||||||||
|
(In
Millions)
|
||||||||||||
|
Revenues
|
$ | 7,528 | $ | 7,776 | $ | 9,395 | ||||||
|
Expenses:
|
||||||||||||
|
Natural
gas
|
5,909 | 5,995 | 7,466 | |||||||||
|
Operation
and maintenance
|
798 | 800 | 828 | |||||||||
|
Depreciation
and amortization
|
200 | 215 | 218 | |||||||||
|
Taxes
other than income taxes
|
149 | 140 | 166 | |||||||||
|
Total
|
7,056 | 7,150 | 8,678 | |||||||||
|
Operating
Income
|
472 | 626 | 717 | |||||||||
|
Other
Income (Expense):
|
||||||||||||
|
Interest
and other finance charges
|
(167 | ) | (187 | ) | (206 | ) | ||||||
|
Equity
in earnings of unconsolidated affiliates
|
6 | 16 | 51 | |||||||||
|
Other,
net
|
12 | 5 | 9 | |||||||||
|
Total
|
(149 | ) | (166 | ) | (146 | ) | ||||||
|
Income
Before Income Taxes
|
323 | 460 | 571 | |||||||||
|
Income
tax expense
|
(116 | ) | (173 | ) | (228 | ) | ||||||
|
Net
Income
|
$ | 207 | $ | 287 | $ | 343 | ||||||
See Notes
to the Company’s Consolidated Financial Statements
(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
STATEMENTS
OF CONSOLIDATED COMPREHENSIVE INCOME
|
Year
Ended December 31,
|
||||||||||||
|
2006
|
2007
|
2008
|
||||||||||
|
(In
Millions)
|
||||||||||||
|
Net
income
|
$ | 207 | $ | 287 | $ | 343 | ||||||
|
Other
comprehensive income (loss), net of tax:
|
||||||||||||
|
Adjustment
to pension and other postretirement plans (net of tax
of
$-0-, a tax benefit of $6, and net of tax of $3)
|
— | 13 | (13 | ) | ||||||||
|
Net
deferred gain from cash flow hedges (net of tax of $11, $6 and
$-0-)
|
22 | 12 | — | |||||||||
|
Reclassification
of net deferred gain from cash flow hedges realized in net income (net of
tax of $3, $20 and $3)
|
(7 | ) | (33 | ) | (5 | ) | ||||||
|
Other
comprehensive income (loss)
|
15 | (8 | ) | (18 | ) | |||||||
|
Comprehensive
income
|
$ | 222 | $ | 279 | $ | 325 | ||||||
See Notes
to the Company’s Consolidated Financial Statements
(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
CONSOLIDATED
BALANCE SHEETS
|
December 31,
|
||||||||
|
2007
|
2008
|
|||||||
|
(In
Millions)
|
||||||||
|
ASSETS
|
||||||||
|
Current
Assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 1 | $ | 1 | ||||
|
Accounts
receivable, net
|
732 | 774 | ||||||
|
Accrued
unbilled revenue
|
456 | 480 | ||||||
|
Accounts
and notes receivable — affiliated companies
|
82 | 9 | ||||||
|
Inventory
|
430 | 495 | ||||||
|
Non-trading
derivative assets
|
38 | 118 | ||||||
|
Deferred
income tax assets
|
40 | 25 | ||||||
|
Prepaid
expenses and other current assets
|
235 | 327 | ||||||
|
Total
current assets
|
2,014 | 2,229 | ||||||
|
Property,
Plant and Equipment, Net
|
5,031 | 5,363 | ||||||
|
Other
Assets:
|
||||||||
|
Goodwill
|
1,696 | 1,696 | ||||||
|
Non-trading
derivative assets
|
11 | 20 | ||||||
|
Investment
in unconsolidated affiliates
|
88 | 345 | ||||||
|
Notes
receivable from unconsolidated affiliates
|
148 | 323 | ||||||
|
Other
|
146 | 235 | ||||||
|
Total
other assets
|
2,089 | 2,619 | ||||||
|
Total
Assets
|
$ | 9,134 | $ | 10,211 | ||||
|
LIABILITIES
AND STOCKHOLDER’S EQUITY
|
||||||||
|
Current
Liabilities:
|
||||||||
|
Short-term
borrowings
|
$ | 232 | $ | 153 | ||||
|
Current
portion of long-term debt
|
307 | 7 | ||||||
|
Accounts
payable
|
661 | 722 | ||||||
|
Accounts
and notes payable — affiliated companies
|
144 | 33 | ||||||
|
Taxes
accrued
|
118 | 99 | ||||||
|
Interest
accrued
|
59 | 54 | ||||||
|
Customer
deposits
|
59 | 59 | ||||||
|
Non-trading
derivative liabilities
|
60 | 87 | ||||||
|
Other
|
186 | 302 | ||||||
|
Total
current liabilities
|
1,826 | 1,516 | ||||||
|
Other
Liabilities:
|
||||||||
|
Accumulated
deferred income taxes, net
|
778 | 864 | ||||||
|
Non-trading
derivative liabilities
|
14 | 47 | ||||||
|
Benefit
obligations
|
116 | 114 | ||||||
|
Regulatory
liabilities
|
474 | 508 | ||||||
|
Other
|
167 | 101 | ||||||
|
Total
other liabilities
|
1,549 | 1,634 | ||||||
|
Long-Term
Debt
|
2,645 | 3,712 | ||||||
|
Commitments
and Contingencies (Note 9)
|
||||||||
|
Stockholder’s
Equity
|
3,114 | 3,349 | ||||||
|
Total
Liabilities And Stockholder’s Equity
|
$ | 9,134 | $ | 10,211 | ||||
See Notes
to the Company’s Consolidated Financial Statements
(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
STATEMENTS
OF CONSOLIDATED CASH FLOWS
|
Year
Ended December 31,
|
||||||||||||
|
2006
|
2007
|
2008
|
||||||||||
|
(In
Millions)
|
||||||||||||
|
Cash
Flows from Operating Activities:
|
||||||||||||
|
Net
income
|
$ | 207 | $ | 287 | $ | 343 | ||||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
Depreciation
and amortization
|
200 | 215 | 218 | |||||||||
|
Deferred
income taxes
|
17 | 64 | 92 | |||||||||
|
Amortization
of deferred financing costs
|
8 | 8 | 9 | |||||||||
|
Write-down
of natural gas inventory
|
66 | 11 | 30 | |||||||||
|
Equity
in earnings of unconsolidated affiliates, net of
distributions
|
(5 | ) | (13 | ) | (51 | ) | ||||||
|
Changes
in other assets and liabilities:
|
||||||||||||
|
Accounts
receivable and unbilled revenues, net
|
248 | 14 | (66 | ) | ||||||||
|
Accounts
receivable/payable, affiliates
|
(19 | ) | (8 | ) | 41 | |||||||
|
Inventory
|
(78 | ) | (105 | ) | (95 | ) | ||||||
|
Accounts
payable
|
(262 | ) | (175 | ) | 60 | |||||||
|
Fuel
cost recovery
|
111 | (93 | ) | 45 | ||||||||
|
Interest
and taxes accrued
|
(4 | ) | 23 | (24 | ) | |||||||
|
Net
non-trading derivative assets and liabilities
|
(18 | ) | 13 | (19 | ) | |||||||
|
Margin
deposits, net
|
(156 | ) | 65 | (182 | ) | |||||||
|
Other
current assets
|
(80 | ) | (27 | ) | (8 | ) | ||||||
|
Other
current liabilities
|
29 | (16 | ) | 17 | ||||||||
|
Other
assets
|
6 | (7 | ) | (3 | ) | |||||||
|
Other
liabilities
|
18 | (12 | ) | (14 | ) | |||||||
|
Other,
net
|
(15 | ) | (3 | ) | (33 | ) | ||||||
|
Net
cash provided by operating activities
|
273 | 241 | 360 | |||||||||
|
Cash
Flows from Investing Activities:
|
||||||||||||
|
Capital
expenditures
|
(599 | ) | (676 | ) | (532 | ) | ||||||
|
Increase
in notes receivable from unconsolidated affiliates
|
— | (148 | ) | (175 | ) | |||||||
|
Investment
in unconsolidated affiliates
|
(13 | ) | (39 | ) | (206 | ) | ||||||
|
Other,
net
|
(9 | ) | (10 | ) | 34 | |||||||
|
Net
cash used in investing activities
|
(621 | ) | (873 | ) | (879 | ) | ||||||
|
Cash
Flows from Financing Activities:
|
||||||||||||
|
Increase
(decrease) in short-term borrowings, net
|
187 | 45 | (79 | ) | ||||||||
|
Long-term
revolving credit facilities, net
|
— | 150 | 776 | |||||||||
|
Payments
of long-term debt
|
(152 | ) | (7 | ) | (307 | ) | ||||||
|
Proceeds
from long-term debt
|
324 | 650 | 300 | |||||||||
|
Decrease
in notes with affiliates, net
|
(103 | ) | (107 | ) | (79 | ) | ||||||
|
Contribution
from parent
|
168 | — | — | |||||||||
|
Dividends
to parent
|
(100 | ) | (100 | ) | (100 | ) | ||||||
|
Debt
issuance costs
|
(1 | ) | (6 | ) | (2 | ) | ||||||
|
Other,
net
|
(1 | ) | 3 | 10 | ||||||||
|
Net
cash provided by financing activities
|
322 | 628 | 519 | |||||||||
|
Net
Decrease in Cash and Cash Equivalents
|
(26 | ) | (4 | ) | — | |||||||
|
Cash
and Cash Equivalents at Beginning of the Year
|
31 | 5 | 1 | |||||||||
|
Cash
and Cash Equivalents at End of the Year
|
$ | 5 | $ | 1 | $ | 1 | ||||||
|
Supplemental
Disclosure of Cash Flow Information:
|
||||||||||||
|
Cash
Payments:
|
||||||||||||
|
Interest,
net of capitalized interest
|
$ | 162 | $ | 167 | $ | 210 | ||||||
|
Income
taxes (refunds)
|
(25 | ) | 106 | 145 | ||||||||
|
Non-cash
transactions:
|
||||||||||||
|
Accounts
payable related to capital expenditures
|
$ | 142 | $ | 51 | $ | 52 | ||||||
See Notes
to the Company’s Consolidated Financial Statements
(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
STATEMENTS
OF CONSOLIDATED STOCKHOLDER’S EQUITY
|
2006
|
2007
|
2008
|
||||||||||||||||||||||
|
Shares
|
Amount
|
Shares
|
Amount
|
Shares
|
Amount
|
|||||||||||||||||||
|
(In
millions, except share amounts)
|
||||||||||||||||||||||||
|
Common
Stock
|
||||||||||||||||||||||||
|
Balance,
beginning of year
|
1,000 | $ | — | 1,000 | $ | — | 1,000 | $ | — | |||||||||||||||
|
Balance,
end of year
|
1,000 | — | 1,000 | — | 1,000 | — | ||||||||||||||||||
|
Additional
Paid-in-Capital
|
||||||||||||||||||||||||
|
Balance,
beginning of year
|
2,404 | 2,403 | 2,406 | |||||||||||||||||||||
|
Contribution
to parent
|
(3 | ) | — | — | ||||||||||||||||||||
|
Other
|
2 | 3 | 10 | |||||||||||||||||||||
|
Balance,
end of year
|
2,403 | 2,406 | 2,416 | |||||||||||||||||||||
|
Retained
Earnings
|
||||||||||||||||||||||||
|
Balance,
beginning of year
|
398 | 505 | 692 | |||||||||||||||||||||
|
Net
income
|
207 | 287 | 343 | |||||||||||||||||||||
|
Dividend
to parent
|
(100 | ) | (100 | ) | (100 | ) | ||||||||||||||||||
|
Balance,
end of year
|
505 | 692 | 935 | |||||||||||||||||||||
|
Accumulated Other
Comprehensive Income
|
||||||||||||||||||||||||
|
Balance,
end of year:
|
||||||||||||||||||||||||
|
Net
deferred gain from cash flow hedges
|
26 | 5 | — | |||||||||||||||||||||
|
Adjustment
to pension and postretirement plans
|
(2 | ) | 11 | (2 | ) | |||||||||||||||||||
|
Total
accumulated other comprehensive income, end of year
|
24 | 16 | (2 | ) | ||||||||||||||||||||
|
Total Stockholder’s
Equity
|
$ | 2,932 | $ | 3,114 | $ | 3,349 | ||||||||||||||||||
See Notes
to the Company’s Consolidated Financial Statements
CENTERPOINT
ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
|
1.
|
Background
|
CenterPoint
Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, the
Company), owns and operates natural gas distribution systems in six states.
Subsidiaries of the Company own interstate natural gas pipelines and gas
gathering systems and provide various ancillary services. A wholly owned
subsidiary of the Company offers variable and fixed-price physical natural gas
supplies primarily to commercial and industrial customers and electric and gas
utilities. CERC Corp. is a Delaware corporation.
The
Company is an indirect wholly owned subsidiary of CenterPoint Energy, Inc.
(CenterPoint Energy), a public utility holding company.
For a
description of the Company’s reportable business segments, see Note
12.
|
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 CERC Corp. and its wholly owned and majority owned subsidiaries are
included in the Company’s consolidated financial statements. All intercompany
transactions and balances are eliminated in consolidation. The Company uses the
equity method of accounting for investments in entities in which the Company has
an ownership interest between 20% and 50% and exercises significant influence.
The Company’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.
(c) Revenues
The
Company records revenue for natural gas sales and services under the accrual
method and these revenues are recognized upon delivery to customers. 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 services are provided.
(d) Long-Lived
Assets and Intangibles
The
Company records property, plant and equipment at historical cost. The Company
expenses repair and maintenance costs as incurred. Property, plant and equipment
includes the following:
|
Weighted
Average Useful
Lives |
December 31,
|
|||||||||||
|
(Years)
|
2007
|
2008
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Natural
Gas Distribution
|
32
|
$ | 3,065 | $ | 3,266 | |||||||
|
Competitive
Natural Gas Sales and Services
|
23
|
59 | 67 | |||||||||
|
Interstate
Pipelines
|
56
|
2,194 | 2,334 | |||||||||
|
Field
Services
|
51
|
493 | 601 | |||||||||
|
Other
property
|
13
|
26 | 45 | |||||||||
|
Total
|
5,837 | 6,313 | ||||||||||
|
Accumulated
depreciation and amortization:
|
||||||||||||
|
Natural
Gas Distribution
|
590 | 708 | ||||||||||
|
Competitive
Natural Gas Sales and Services
|
9 | 11 | ||||||||||
|
Interstate
Pipelines
|
160 | 182 | ||||||||||
|
Field
Services
|
29 | 28 | ||||||||||
|
Other
property
|
18 | 21 | ||||||||||
|
Total
accumulated depreciation and amortization
|
806 | 950 | ||||||||||
|
Property,
plant and equipment, net
|
$ | 5,031 | $ | 5,363 | ||||||||
Goodwill
by reportable business segment as of December 31, 2007 and 2008 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 |
The
Company performs its goodwill impairment tests at least annually and evaluates
goodwill when events or changes in circumstances indicate that the carrying
value of these assets 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.
The
Company performed the test at July 1, 2008, the Company’s annual impairment
testing date, and determined that no impairment charge for goodwill was
required.
The
Company 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.
At
December 31, 2007 and 2008, the Company’s asset retirement obligations were
$62 million and $46 million, respectively. The decrease in asset
retirement obligations in 2008 of $16 million is primarily attributable to
the increase in the credit-adjusted risk-free rate used to value the asset
retirement obligations as of the end of the period.
43
The
decrease in asset retirement obligations results in an increase in removal cost
regulatory liabilities as discussed in Note 2(e).
(e) Regulatory
Assets and Liabilities
The
Company applies the accounting policies established in Statement of Financial
Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types
of Regulation” (SFAS No. 71), to 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 the Company’s
Consolidated Balance Sheets as of December 31, 2007 and 2008:
|
December 31,
|
||||||||
|
2007
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Regulatory
assets in other long-term assets
|
$ | 53 | $ | 53 | ||||
|
Regulatory
liabilities
|
(474 | ) | (508 | ) | ||||
|
Net
|
$ | (421 | ) | $ | (455 | ) | ||
The
Company’s rate-regulated businesses recognize removal costs as a component of
depreciation expense in accordance with regulatory treatment. As of
December 31, 2007 and 2008, these removal costs of $445 million and
$478 million, respectively, are classified as regulatory liabilities in the
Consolidated Balance Sheets. A portion of the amount of removal
costs that relate to asset retirement obligations have been reclassified from a
regulatory liability to an asset retirement liability in accordance with
Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47,
“Accounting for Conditional Asset Retirement Obligations”
(FIN 47).
(f) Depreciation
and Amortization Expense
Depreciation
is computed using the straight-line method based on economic lives or a
regulatory-mandated recovery period. Amortization expense includes amortization
of regulatory assets and other intangibles.
The
following table presents depreciation and amortization expense for 2006, 2007
and 2008:
|
Year
Ended December 31,
|
||||||||||||
|
2006
|
2007
|
2008
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Depreciation
expense
|
$ | 181 | $ | 193 | $ | 200 | ||||||
|
Amortization
expense
|
19 | 22 | 18 | |||||||||
|
Total
depreciation and amortization expense
|
$ | 200 | $ | 215 | $ | 218 | ||||||
(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 SFAS No. 71. Interest and AFUDC for subsidiaries that
apply SFAS No. 71 are capitalized as a component of projects under construction
and will be amortized over the assets’ estimated useful lives. During 2006, 2007
and 2008, the Company capitalized interest and AFUDC of $6 million,
$12 million and $5 million, respectively.
(h) Income
Taxes
The
Company is included in the consolidated income tax returns of CenterPoint
Energy. The Company calculates its income tax provision on a separate return
basis under a tax sharing agreement with CenterPoint Energy. Pursuant to the tax
sharing agreement with CenterPoint Energy, in 2006, the Company received
allocations of CenterPoint Energy’s tax expense totaling
$3 million.
The
Company uses the asset and liability method of accounting for deferred income
taxes in accordance with SFAS No. 109, “Accounting for 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. A valuation
allowance is established against deferred tax assets for which management
believes realization is not considered more likely than not. Current federal and
certain state income taxes are payable to or receivable from CenterPoint
Energy.
Prior to
2007, the Company evaluated uncertain income tax positions and recorded a tax
liability for those positions that management believed were probable of an
unfavorable outcome and could be reasonably estimated. Effective January 1,
2007, the Company accounts for the tax effects of uncertain income tax positions
in accordance with FIN 48, “Accounting for Uncertainty in Income Taxes – an
Interpretation of FASB Statement No. 109” (FIN 48). The Company recognizes
interest and penalties as a component of income tax expense. For
additional information regarding income taxes, see Note 8.
(i) Accounts
Receivable and Allowance for Doubtful Accounts
Accounts
receivable are net of an allowance for doubtful accounts of $37 million and
$33 million at December 31, 2007 and 2008, respectively. The provision
for doubtful accounts in the Company’s Statements of Consolidated Income for
2006, 2007 and 2008 was $37 million, $42 million and $53 million,
respectively.
On
November 25, 2008, the Company replaced a receivables facility that had
terminated on October 28, 2008 with a new 364-day receivables facility.
Availability under the new facility ranges from $128 million to
$375 million, reflecting seasonal changes in receivables
balances. At December 31, 2007 and 2008 the facility size was
$300 million and $128 million, respectively. As of December 31, 2007
and 2008, advances under the receivables facilities were $232 million and
$78 million, 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 the Company’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 the Company’s Natural Gas Distribution business
segment are primarily valued at weighted average cost. During 2007
and 2008, the Company recorded $11 million and $30 million,
respectively, in write-downs of natural gas inventory to the lower of average
cost or market.
|
December 31,
|
||||||||
|
2007
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Materials
and supplies
|
$ | 35 | $ | 54 | ||||
|
Natural
gas
|
395 | 441 | ||||||
|
Total
inventory
|
$ | 430 | $ | 495 | ||||
(k) Derivative
Instruments
The
Company 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. Such contracts are
recognized in the Company’s Consolidated Balance Sheets at their fair value
unless the Company elects the normal purchase and sales exemption for qualified
physical transactions. A derivative contract may be designated as a normal
purchase or sale if the intent is to physically receive or deliver the product
for use or sale in the normal course of business. If derivative contracts are
designated as a cash flow hedge according to SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities” (SFAS No. 133), the effective
portions of the changes in their fair values are reflected initially as a
separate component of shareholders’ equity and subsequently recognized in income
at the same time the hedged items impact earnings. The ineffective portions of
changes in fair values of derivatives designated as hedges are immediately
recognized in income. Changes in other derivatives not designated as normal or
as a cash flow hedge are recognized in income as they occur. The Company does
not enter into or hold derivative instruments for trading purposes.
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 the Company’s marketing, risk management services and hedging
activities. The committee’s duties are to establish the Company’s commodity risk
policies, allocate risk capital within limits established by CenterPoint
Energy’s board of directors, 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.
The
Company’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) Environmental
Costs
The
Company expenses or capitalizes environmental expenditures, as appropriate,
depending on their future economic benefit. The Company expenses amounts that
relate to an existing condition caused by past operations that do not have
future economic benefit. The Company records undiscounted liabilities related to
these future costs when environmental assessments and/or remediation activities
are probable and the costs can be reasonably estimated.
(m) Statements
of Consolidated Cash Flows
For
purposes of reporting cash flows, the Company considers cash equivalents to be
short-term, highly liquid investments with maturities of three months or less
from the date of purchase.
(n) New
Accounting Pronouncements
In April
2007, the FASB issued Staff Position No. FIN 39-1, “Amendment of FASB
Interpretation No. 39” (FIN 39-1), which permits companies that enter into
master netting arrangements to offset cash collateral receivables or payables
with net derivative positions under certain circumstances. The Company adopted
FIN 39-1 effective January 1, 2008 and began netting cash collateral
receivables and payables and also its derivative assets and liabilities with the
same counterparty subject to master netting agreements.
In
February 2007, the FASB issued Statement of Financial Accounting Standard
(SFAS) No. 159, “The Fair Value Option for Financial Assets and
Financial Liabilities, including an amendment of FASB Statement No. 115”
(SFAS No. 159). SFAS No. 159 permits the Company to choose,
at specified election dates, to measure eligible items at fair value (the “fair
value option”). The Company would report unrealized gains and losses on items
for which the fair value option has been elected in earnings at each subsequent
reporting period. This accounting standard is effective as of the beginning of
the first fiscal year that begins after November 15, 2007 but is not
required to be applied. The Company currently has no plans to apply SFAS No.
159.
In
December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations”
(SFAS No. 141R). SFAS
No. 141R will significantly change the accounting for business combinations.
Under SFAS No. 141R, an acquiring entity will be required to recognize all the
assets acquired and liabilities assumed in a transaction at the acquisition date
fair value with limited exceptions. SFAS No. 141R also includes a substantial
number of new disclosure requirements and applies prospectively to business
combinations for which the acquisition date is on or after the beginning of the
first annual reporting period beginning on or after December 15, 2008. As the
provisions of SFAS No. 141R are applied prospectively, the impact to the Company
cannot be determined until applicable transactions occur.
In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements - An Amendment of ARB No. 51” (SFAS No. 160).
SFAS No. 160 establishes new accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. This accounting standard is effective for fiscal years, and interim
periods within those fiscal years, beginning on or after December 15, 2008. The
Company will adopt SFAS No. 160 as of January 1, 2009. The Company expects that
the adoption of SFAS No. 160 will not have a material impact on its financial
position, results of operations or cash flows.
In
March 2008, the FASB issued SFAS No. 161, “Disclosures about
Derivative Instruments and Hedging Activities - an amendment of FASB Statement
No. 133” (SFAS No. 161). SFAS No. 161 amends SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133)
and 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.
SFAS No. 161 is effective for fiscal years and interim periods
beginning after November 15, 2008. The Company expects that the adoption of
SFAS No. 161 will not have a material impact on its financial position, results
of operations or cash flows.
(o) Employee
Benefit Plans
Pension
Plans
Substantially
all of the Company’s employees participate in CenterPoint Energy’s qualified
non-contributory defined benefit pension plan. 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.
CenterPoint
Energy’s funding policy is to review amounts annually in accordance with
applicable regulations in order to achieve adequate funding of projected benefit
obligations. Pension expense is allocated to the Company based on covered
employees. This calculation is intended to allocate pension costs in the same
manner as a separate employer plan. Assets of the plan are not segregated or
restricted by CenterPoint Energy’s participating subsidiaries. The Company
recognized pension expense of $16 million and $5 million for the years
ended December 31, 2006 and 2007, respectively, and pension income of
$3 million for the year ended December 31, 2008.
In
addition to the plan, the Company participates in CenterPoint Energy’s
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. The expense associated with the non-qualified pension plan
was less than $1 million for each of the years ended December 31, 2006
and 2007, respectively, and $1 million for the year ended December 31,
2008.
Savings
Plan
The
Company participates in CenterPoint Energy’s qualified savings plan, which
includes a cash or deferred arrangement under Section 401(k) of the Internal
Revenue Code of 1986, as amended. 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%, which increased from 16% in prior years, of
compensation. Effective January 1, 2009, the Company matches 100% of the first
6% of each employee’s compensation contributed. The Company previously matched
75% of the first 6% of each employee’s compensation contributed with the
potential for an additional discretionary match of up to 50% of the first 6% of
each employee’s compensation contributed. The matching contributions are fully
vested at all times. CenterPoint Energy allocates to the Company the savings
plan benefit expense related to the Company’s employees. Savings plan
benefit expense was $17 million for each of the years ended December 31,
2006 and 2007 and $18 million for the year ended December 31,
2008.
Postretirement
Benefits
The
Company’s employees participate in CenterPoint Energy’s plans which provide
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 Company is required to fund a portion of its obligations in
accordance with rate orders. All other obligations are funded on a pay-as-you-go
basis.
The net
postretirement benefit cost includes the following components:
|
Year
Ended December 31,
|
||||||||||||
|
2006
|
2007
|
2008
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Service
cost — benefits earned during the period
|
$ | 1 | $ | 1 | $ | 1 | ||||||
|
Interest
cost on projected benefit obligation
|
7 | 7 | 7 | |||||||||
|
Expected
return on plan assets
|
(1 | ) | (1 | ) | (1 | ) | ||||||
|
Amortization
of prior service cost
|
2 | 2 | 2 | |||||||||
|
Other
|
1 | — | — | |||||||||
|
Net
postretirement benefit cost
|
$ | 10 | $ | 9 | $ | 9 | ||||||
The
Company used the following assumptions to determine net postretirement benefit
costs:
|
Year
Ended December 31,
|
||||||||||||
|
2006
|
2007
|
2008
|
||||||||||
|
Discount
rate
|
5.70 | % | 5.85 | % | 6.40 | % | ||||||
|
Expected
return on plan assets
|
4.80 | % | 4.50 | % | 4.50 | % | ||||||
In
determining net periodic benefits cost, the Company uses fair value, as of the
beginning of the year, as its basis for determining expected return on plan
assets.
Following
are reconciliations of the Company’s beginning and ending balances of its
postretirement benefit plan’s benefit obligation, plan assets and funded status
for 2007 and 2008. The measurement dates for plan assets and obligations were
December 31, 2007 and 2008.
|
Year
Ended December 31,
|
||||||||
|
2007
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Change
in Benefit Obligation
|
||||||||
|
Accumulated
benefit obligation, beginning of year
|
$ | 134 | $ | 119 | ||||
|
Service
cost
|
1 | 1 | ||||||
|
Interest
cost
|
7 | 7 | ||||||
|
Benefits
paid
|
(20 | ) | (19 | ) | ||||
|
Medicare
reimbursement
|
3 | 1 | ||||||
|
Participant
contributions
|
4 | 4 | ||||||
|
Actuarial
loss
|
(10 | ) | 7 | |||||
|
Accumulated
benefit obligation, end of year
|
$ | 119 | $ | 120 | ||||
|
Change
in Plan Assets
|
||||||||
|
Plan
assets, beginning of year
|
$ | 20 | $ | 20 | ||||
|
Benefits
paid
|
(20 | ) | (19 | ) | ||||
|
Employer
contributions
|
15 | 14 | ||||||
|
Participant
contributions
|
4 | 4 | ||||||
| Medicare reimbursement received | — | 1 | ||||||
|
Actual
investment return
|
1 | — | ||||||
|
Plan
assets, end of year
|
$ | 20 | $ | 20 | ||||
|
Amounts
Recognized in Balance Sheets
|
||||||||
| Current liabilities-other | (6 | ) | (8 | ) | ||||
|
Other
liabilities-benefit obligations
|
$ | (93 | ) | $ | (92 | ) | ||
|
Net
liability, end of year
|
$ | (99 | ) | $ | (100 | ) | ||
|
Actuarial
Assumptions
|
||||||||
|
Discount
rate
|
6.40 | % | 6.90 | % | ||||
|
Expected
long-term return on assets
|
4.50 | % | 4.50 | % | ||||
|
Healthcare
cost trend rate assumed for the next year
|
7.00 | % | 6.50 | % | ||||
|
Prescription
drug cost trend rate assumed for the next year
|
13.00 | % | 12.00 | % | ||||
|
Rate
to which the cost trend rate is assumed to decline (ultimate trend
rate)
|
5.50 | % | 5.50 | % | ||||
|
Year
that the healthcare rate reaches the ultimate trend rate
|
2012
|
2011
|
||||||
|
Year
that the prescription drug rate reaches the ultimate trend
rate
|
2015
|
|
2014
|
|||||
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
expected duration of obligations specific to the characteristics of CenterPoint
Energy’s plans.
The
expected rate of return assumption was developed by reviewing the targeted asset
allocations and historical index performance of the applicable asset classes
over a 15-year period, adjusted for investment fees and diversification
effects.
For
measurement purposes, healthcare costs are assumed to increase 6.5% during 2009,
after which this rate decreases until reaching the ultimate rate of 5.5% in
2011. Prescription drug costs are assumed to increase 12% in 2009, after which
this rate decreases until reaching the ultimate rate of 5.5% in
2014.
Amounts
recognized in accumulated other comprehensive (income) loss consist of the
following:
|
Year
Ended December 31,
|
||||||||
|
2007
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Unrecognized
actuarial loss
|
$ | 3 | $ | 14 | ||||
|
Unrecognized
prior service cost
|
12 | 10 | ||||||
| 15 | 24 | |||||||
|
Less
deferred tax benefit (1)
|
(26 | ) | (21 | ) | ||||
|
Net
amount recognized in accumulated other comprehensive (income)
loss
|
$ | (11 | ) | $ | 3 | |||
|
(1)
|
The
Company’s postretirement benefit obligation is reduced by the impact of
non-taxable government subsidies under the Medicare Prescription Drug
Act. Because the subsidies are non-taxable, the temporary
difference used in measuring the deferred tax impact is determined on the
unrecognized losses excluding such subsidies. Accordingly, the
unrecognized losses used for determining deferred taxes were
$64 million and $54 million as of December 31, 2007 and
2008, respectively.
|
The
changes in plan assets and benefit obligations recognized in other comprehensive
income during 2008 are as follows:
|
Postretirement
Benefits
|
||||
|
(In
millions)
|
||||
|
Net
gain
|
$ | 11 | ||
|
Amortization
of prior service cost
|
(2 | ) | ||
|
Total
recognized in other comprehensive income
|
$ | 9 | ||
The total
expense recognized in net periodic costs and other comprehensive income was
$18 million for postretirement benefits for the year ended
December 31, 2008.
The
amounts in accumulated other comprehensive income expected to be recognized as
components of net periodic benefit cost during 2009 are as follows:
|
Postretirement
Benefits
|
||||
|
(In
millions)
|
||||
|
Unrecognized
prior service cost
|
$ | 2 | ||
|
Amounts
in other comprehensive income to be recognized as net periodic cost in
2009
|
$ | 2 | ||
Assumed
healthcare cost trend rates have a significant effect on the reported amounts
for the Company’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
|
$ | 5 | $ | (4 | ) | |||
|
Effect
on the total of service and interest cost
|
— | — | ||||||
The
following table displays the weighted average asset allocations as of
December 31, 2007 and 2008 for the Company’s postretirement benefit
plan:
|
December 31,
|
||||||||
|
2007
|
2008
|
|||||||
|
Domestic
equity securities
|
6 | % | 4 | % | ||||
|
Debt
securities
|
93 | 96 | ||||||
|
Cash
|
1 | — | ||||||
|
Total
|
100 | % | 100 | % | ||||
In
managing the investments associated with the postretirement benefit plan, the
Company’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, the Company has adopted and
maintains the following asset allocation ranges for its postretirement benefit
plan:
|
Domestic
equity securities
|
0-10 | % | ||
|
Debt
securities
|
90-100 | % | ||
|
Cash
|
0-2 | % |
The
Company expects to contribute $9 million to its postretirement benefits
plan in 2009. The following benefit payments are expected to be paid by the
postretirement benefit plan:
|
Postretirement
Benefit Plan
|
||||||||
|
Benefit
Payments
|
Medicare
Subsidy
Receipts
|
|||||||
|
(in
millions)
|
||||||||
|
2009
|
$ | 12 | $ | (2 | ) | |||
|
2010
|
13 | (2 | ) | |||||
|
2011
|
13 | (2 | ) | |||||
|
2012
|
14 | (2 | ) | |||||
|
2013
|
14 | (3 | ) | |||||
|
2014-2018
|
73 | (17 | ) | |||||
|
|
Postemployment
Benefits
|
The
Company participates in CenterPoint Energy’s plan that 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 a postemployment benefit cost of $3 million, income of $2
million and cost of $1 million for the years ended December 31, 2006, 2007 and
2008, respectively. Amounts relating to postemployment benefits included in
“Benefit Obligations” in the accompanying Consolidated Balance Sheets at
December 31, 2007 and 2008, were $17 million and $16 million,
respectively.
|
|
Other
Non-Qualified Plans
|
The
Company participates in CenterPoint Energy’s 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 the
Company. During 2006, 2007 and 2008, the benefit expense relating to these
programs was less than $1 million each year. Amounts relating to deferred
compensation plans included in “Benefit Obligations” in the accompanying
Consolidated Balance Sheets at December 31, 2007 and 2008, were
$4 million and $1 million, respectively.
(p) Other
Current Assets and Liabilities
Included
in other current assets on the Consolidated Balance Sheets at December 31,
2007 and 2008 was $47 million and $42 million, respectively, of margin
deposits and $53 million and $128 million, respectively of under
recovered gas cost. Included in other current liabilities on the Consolidated
Balance Sheets at December 31, 2007 and 2008 was $30 million and
$79 million, respectively, of over recovered gas cost.
|
3.
|
Regulatory
Matters
|
(a) Hurricane
Ike
The
Company’s natural gas distribution business (Gas Operations) 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, which struck
the upper Texas coast in September 2008. As of December 31, 2008, Gas
Operations has deferred approximately $4 million of costs related to
Hurricane Ike for recovery as part of future natural gas distribution rate
proceedings.
(b) Rate
Proceedings
Texas. In March 2008, 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 Houston. The request sought to establish uniform
rates, charges and terms and conditions of service for the cities and environs
of the Texas Coast service territory. Of the 47 cities, 23 either affirmatively
approved or allowed the filed rates to go into effect by operation of law.
Nine other cities were represented by the Texas Coast Utilities Coalition (TCUC)
and 15 cities were represented by the Gulf Coast Coalition of Cities (GCCC). In
July 2008, Gas Operations reached a settlement agreement with the GCCC. That
settlement agreement, if implemented across the entire Texas Coast service
territory, would allow Gas Operations a $3.4 million annual increase in
revenues. The TCUC cities denied the rate change request and Gas Operations
appealed the denial of rates to the Railroad Commission. The Railroad Commission
issued an order in October 2008, which, if implemented across the entire Texas
Coast service territory, would result in an annual revenue increase of
$3.7 million. Both the Railroad Commission order and the settlement provide
for an annual rate adjustment mechanism to reflect changes in operating expenses
and revenues as well as changes in capital investment and associated changes in
revenue-related taxes. In December 2008, the Railroad Commission issued an order
on rehearing. Parties filed second motions for rehearing on this
order. On February 26, 2009, the Railroad Commission denied the second motions
on rehearing reaffirming its original decision. In December 2008, Gas
Operations implemented the approved rates for the nine TCUC cities and the
environs. Cities with settled rates have the opportunity to adopt the
rates established by the Railroad Commission or retain the rates agreed in their
settlements.
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
51
in
denying Gas Operations a waiver. The court ordered the case remanded to the MPUC
for reconsideration under the same principles the MPUC had applied in previously
granted waiver requests. The MPUC sought further review of the court of appeals
decision from the Minnesota Supreme Court, and in July 2008, the Minnesota
Supreme Court agreed to review the decision. In January 2009, the
Minnesota Supreme Court heard oral arguments. While there is no deadline for a
decision, a decision is expected by the end of the third quarter of 2009. While
no prediction can be made as to the ultimate outcome, this matter will have no
negative impact on the Company’s financial condition, results of operations or
cash flows.
In
November 2008, Gas Operations filed a request with the MPUC to increase its
rates for utility distribution service. If approved by the MPUC, the
proposed new rates would result in an overall increase in annual revenue of
$59.8 million. The proposed increase would allow Gas Operations to
recover increased operating costs, including higher bad debt and collection
expenses, the cost of improved customer service and inflationary increases in
other expenses. It also would allow recovery of increased costs
related to conservation improvement programs and provide a return for the
additional capital invested to serve its customers. In addition, Gas
Operations is seeking 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. The MPUC is
allowed ten months to issue a final decision; however, an extension of time can
occur in certain circumstances.
|
4.
|
Related
Party Transactions
|
The
Company participates in a “money pool” through which it 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 CenterPoint Energy’s
revolving credit facility or the sale of CenterPoint Energy’s commercial paper.
The Company had money pool borrowings of $67 million and $-0- at
December 31, 2007 and 2008, respectively, which are included in accounts
and notes payable—affiliated companies in the Consolidated Balance
Sheets.
For the
years ended December 31, 2006, 2007 and 2008, the Company had net interest
expense related to affiliate borrowings of $2 million, $3 million and
less than $1 million, respectively.
CenterPoint
Energy provides some corporate services to the Company. The costs of services
have been charged directly to the Company using methods that management believes
are reasonable. These methods include negotiated usage rates, dedicated asset
assignment and proportionate corporate formulas based on operating expenses,
assets, gross margin, employees and a composite of assets, gross margin and
employees. These charges are not necessarily indicative of what would have been
incurred had the Company not been an affiliate. Amounts charged to the Company
for these services were $133 million, $133 million and
$140 million for 2006, 2007 and 2008, respectively, and are included
primarily in operation and maintenance expenses.
Pursuant
to the tax sharing agreement with CenterPoint Energy, the Company received
allocations of CenterPoint Energy’s tax expense of $3 million for 2006
which was recorded in additional paid-in capital.
In each of 2006, 2007 and 2008, the Company paid dividends of $100 million
to its parent.
|
5.
|
Derivative
Instruments
|
The
Company is exposed to various market risks. These risks arise from transactions
entered into in the normal course of business. The Company 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
Cash Flow
Hedges. The Company has entered into certain derivative
instruments that qualify as cash flow hedges under SFAS No. 133. The
objective of these derivative instruments is to hedge the price risk associated
with natural gas purchases and sales to reduce cash flow variability related to
meeting the Company’s wholesale and
52
retail
customer obligations. During the year ended December 31, 2006, hedge
ineffectiveness resulted in a gain of $2 million and during both the years
ended December 31, 2007 and 2008, hedge ineffectiveness resulted in a loss of
less than $1 million from derivatives that qualify for and are designated
as cash flow hedges. No component of the derivative instruments’ gain or loss
was excluded from the assessment of effectiveness. If it becomes probable that
an anticipated transaction being hedged will not occur, the Company realizes in
net income the deferred gains and losses previously recognized in accumulated
other comprehensive loss. When an anticipated transaction being hedged affects
earnings, the accumulated deferred gain or loss recognized in accumulated other
comprehensive loss is reclassified and included in the Statements of
Consolidated Income under the “Expenses” caption “Natural gas.” Cash flows
resulting from these transactions in non-trading energy derivatives are included
in the Statements of Consolidated Cash Flows in the same category as the item
being hedged. As of December 31, 2008, the Company expects less than
$1 million in accumulated other comprehensive income to be reclassified as
a decrease in Natural gas expense during the next twelve
months.
The
length of time the Company is hedging its exposure to the variability in future
cash flows using derivative instruments that have been designated and have
qualified as cash flow hedging instruments is less than one year. The Company’s
policy is not to exceed ten years in hedging its exposure.
Other Derivative
Instruments. The Company enters into certain derivative
instruments to manage physical commodity price risks that do not qualify or are
not designated as cash flow or fair value hedges under SFAS No. 133.
The Company utilizes these financial instruments to manage physical commodity
price risks and does not engage in proprietary or speculative commodity trading.
During the year ended December 31, 2006, the Company decreased natural gas
expense from unrealized net gains of $34 million. During the year ended
December 31, 2007, the Company increased natural gas expense from
unrealized net losses of $10 million. During the year ended
December 31, 2008, the Company increased 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.
Weather
Derivatives. The Company has weather normalization or other
rate mechanisms that mitigate the impact of weather in Arkansas, Louisiana,
Oklahoma and a portion of Texas. The remaining Gas Operations jurisdictions,
Minnesota, Mississippi and most of Texas, do not have such mechanisms. As a
result, fluctuations from normal weather may have a significant positive or
negative effect on the results of these operations.
In 2007,
the Company entered into heating-degree day swaps to mitigate the effect of
fluctuations from normal weather on its financial position and cash flows for
the 2007-2008 winter heating season. The swaps were based on ten-year normal
weather and provided for a maximum payment by either party of $18 million.
In July 2008, the Company entered into heating-degree day swaps to mitigate the
effect of fluctuations from normal weather on its financial position and cash
flows for the 2008-2009 winter heating season. The swaps are based on ten-year
normal weather and provide for a maximum payment by either party of
$11 million. During the years ended December 31, 2007 and 2008, the
Company recognized losses of $-0- and $17 million, respectively, related to
these swaps. Such amounts were substantially offset by increased margin due to
colder than normal weather. These weather derivative losses are included in
revenues in the Statements of Consolidated Income.
(b) Credit
Risks
In
addition to the risk associated with price movements, credit risk is also
inherent in the Company’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 the non-trading
derivative assets of the Company as of December 31, 2007 and 2008 (in
millions):
|
December 31,
2007
|
December 31,
2008
|
|||||||||||||||
|
Investment
Grade(1)
|
Total
|
Investment
Grade(1)
|
Total
|
|||||||||||||
|
Energy
marketers
|
$ | 16 | $ | 18 | $ | 8 | $ | 9 | ||||||||
|
Financial
institutions
|
25 | 25 | 4 | 4 | ||||||||||||
|
Retail
end users (2)
|
3 | 7 | 5 | 125 | ||||||||||||
|
Total
|
$ | 44 | $ | 50 | $ | 17 | $ | 138 | ||||||||
__________
|
(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, the Company 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.
|
|
6.
|
Fair
Value Measurements
|
Effective
January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements”
(SFAS No. 157), which requires additional disclosures about the Company’s
financial assets and liabilities that are measured at fair value. FASB
Staff Position No. FAS 157-2 delays the effective date for SFAS No. 157 for
nonfinancial assets and liabilities, except for items that are recognized or
disclosed at fair value in the financial statements on a recurring basis, to
fiscal years, and interim periods within those fiscal years, beginning after
November 15, 2008. The Company has elected to defer the adoption of SFAS No. 157
for its goodwill impairment test and the measurement of asset retirement
obligations until January 1, 2009 as permitted. Beginning in January
2008, assets and liabilities recorded at fair value in the Consolidated Balance
Sheet are categorized based upon the level of judgment associated with the
inputs used to measure their value. Hierarchical levels, as defined in SFAS No.
157 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. The Company’s assessment of the significance of a
particular input to the fair value measurement in its entirety requires
judgment, and considers factors specific to the asset. Generally, assets and
liabilities carried at fair value and included in this category are financial
derivatives.
The
following table presents information about the Company’s assets and liabilities
(including derivatives that are presented net) measured at fair value on a
recurring basis as of December 31, 2008, and indicates the fair value
hierarchy of the valuation techniques utilized by the Company 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
|
$ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||
|
Investments,
including money
market
funds
|
11 | — | — | — | 11 | |||||||||||||||
|
Derivative
assets
|
8 | 155 | 49 | (74 | ) | 138 | ||||||||||||||
|
Total assets
|
$ | 20 | $ | 155 | $ | 49 | $ | (74 | ) | $ | 150 | |||||||||
|
Liabilities
|
||||||||||||||||||||
|
Derivative liabilities
|
44 | 244 | 107 | (261 | ) | 134 | ||||||||||||||
|
Total
liabilities
|
$ | 44 | $ | 244 | $ | 107 | $ | (261 | ) | $ | 134 | |||||||||
|
(1)
|
Amounts
represent the impact of legally enforceable master netting agreements that
allow the Company to settle positive and negative positions and also cash
collateral held or placed with the same
counterparties.
|
The
following table presents additional information about assets or liabilities,
including derivatives that are measured at fair value on a recurring basis for
which the Company has utilized Level 3 inputs to determine fair value, for the
year ended December 31, 2008:
|
Fair
Value Measurements
Using
Significant
Unobservable
Inputs
(Level
3)
|
||||
|
Derivative
assets and
liabilities,
net
|
||||
|
(in
millions)
|
||||
|
Beginning
liability balance as of January 1, 2008
|
$ | (3 | ) | |
|
Total
gains or (losses) (realized and unrealized):
|
||||
|
Included
in deferred fuel cost recovery
|
(10 | ) | ||
|
Included
in earnings
|
(11 | ) | ||
|
Purchases,
sales, other settlements, net:
|
||||
|
Included
in deferred fuel cost recovery
|
(41 | ) | ||
|
Included
in earnings
|
6 | |||
|
Net
transfers into Level 3
|
1 | |||
|
Ending
liability balance as of December 31, 2008
|
$ | (58 | ) | |
|
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 | ||
|
7.
|
Short-term
Borrowings and Long-term Debt
|
|
December 31,
2007
|
December 31,
2008
|
|||||||||||||||
|
Long-Term
|
Current(1)
|
Long-Term
|
Current(1)
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Short-term
borrowings:
|
||||||||||||||||
|
CERC
Corp. receivables facility
|
$ | — | $ | 232 | $ | — | $ | 78 | ||||||||
|
Inventory
financing
|
— | — | — | 75 | ||||||||||||
|
Total
short-term borrowings
|
— | 232 | — | 153 | ||||||||||||
|
Long-term
debt:
|
||||||||||||||||
|
Convertible
subordinated debentures 6.00%
due
2012
|
50 | 7 | 44 | 7 | ||||||||||||
|
Senior
notes 5.95% to 7.875% due 2008 to 2037
|
2,447 | 300 | 2,747 | — | ||||||||||||
|
Bank
loans due 2012(2)
|
150 | — | 926 | — | ||||||||||||
|
Unamortized
discount and premium(3)
|
(2 | ) | — | (5 | ) | — | ||||||||||
|
Total
long-term debt
|
2,645 | 307 | 3,712 | 7 | ||||||||||||
|
Total
debt
|
$ | 2,645 | $ | 539 | $ | 3,712 | $ | 160 | ||||||||
|
(1)
|
Includes
amounts due or exchangeable within one year of the date
noted.
|
|
|
(2)
|
Classified
as long-term debt because the termination date of the facility under which
the funds were borrowed is more than one year beyond the dates referenced
in the table.
|
|
|
(3)
|
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 at both December 31, 2007 and 2008, which is being
amortized over the respective remaining term of the related long-term
debt.
|
(a) Short-term
Borrowings
Receivables Facility. On
November 25, 2008, the Company replaced a receivables facility that had
terminated on October 28, 2008 with a new 364-day receivables facility.
Availability under the new facility ranges from $128 million to
$375 million, reflecting seasonal changes in receivables
balances. At December 31, 2007 and 2008 the facility size was
$300 million and $128 million, respectively. As of December 31, 2007
and 2008, advances under the receivables facilities were $232 million and
$78 million, respectively. As of December 31, 2008, advances had
an interest rate of 3.81%.
Inventory Financing. In
December 2008, the Company 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, as of December 31, 2008, the Company’s financial
statements reflect natural gas inventory of $75 million and a financing
obligation of $75 million related to this transaction.
(b) Long-term
Debt
Senior Notes. In
May 2008, the Company issued $300 million aggregate principal amount of
senior notes due in May 2018 with an interest rate of 6.00%. The proceeds from
the sale of the senior notes were used for general corporate purposes, including
capital expenditures, working capital and loans to or investments in
affiliates.
Revolving Credit
Facility. The Company’s $950 million revolving credit
facility’s first drawn cost is the London Interbank Offered Rate (LIBOR) plus
45 basis points based on the Company’s current credit
ratings. The facility contains covenants, including a debt to total
capitalization covenant of 65%. Under the 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 Company’s credit rating.
As of
December 31, 2008, the Company had $926 million of borrowings and no
letters of credit under its $950 million credit facility. The
Company had no commercial paper outstanding at December 31,
2008. The Company was in compliance with all debt covenants as of
December 31, 2008.
Maturities. The
Company’s consolidated maturities of long-term debt and sinking fund
requirements are $7 million in 2009, $7 million in 2010,
$556 million in 2011, $957 million in 2012 and $765 million in
2013.
|
8.
|
Income
Taxes
|
The
components of the Company’s income tax expense (benefit) were as
follows:
|
Year
Ended December 31,
|
||||||||||||
|
2006
|
2007
|
2008
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | 97 | $ | 81 | $ | 118 | ||||||
|
State
|
36 | 28 | 18 | |||||||||
|
Total
current
|
133 | 109 | 136 | |||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
(22 | ) | 58 | 60 | ||||||||
|
State
|
5 | 6 | 32 | |||||||||
|
Total
deferred
|
(17 | ) | 64 | 92 | ||||||||
|
Income
tax expense
|
$ | 116 | $ | 173 | $ | 228 | ||||||
A
reconciliation of the federal statutory income tax rate to the effective income
tax rate is as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2006
|
2007
|
2008
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Income
before income taxes
|
$ | 323 | $ | 460 | $ | 571 | ||||||
|
Federal
statutory rate
|
35 | % | 35 | % | 35 | % | ||||||
|
Income
taxes at statutory rate
|
113 | 161 | 200 | |||||||||
|
Net
addition (reduction) in taxes resulting from:
|
||||||||||||
|
State
income taxes, net of valuation allowance and federal income
tax
|
27 | 22 | 32 | |||||||||
|
Decrease
in settled and uncertain income tax positions
|
(20 | ) | (8 | ) | (1 | ) | ||||||
|
Other,
net
|
(4 | ) | (2 | ) | (3 | ) | ||||||
|
Total
|
3 | 12 | 28 | |||||||||
|
Income
tax expense
|
$ | 116 | $ | 173 | $ | 228 | ||||||
|
Effective
income tax rate
|
36.1 | % | 37.6 | % | 40.0 | % | ||||||
The tax
effects of temporary differences that give rise to significant portions of
deferred tax assets and liabilities were as follows:
|
December 31,
|
||||||||
|
2007
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Deferred
tax assets:
|
||||||||
|
Current:
|
||||||||
|
Allowance
for doubtful accounts
|
$ | 16 | $ | 13 | ||||
|
Deferred
gas costs
|
26 | 12 | ||||||
|
Total
current deferred tax assets
|
42 | 25 | ||||||
|
Non-current:
|
||||||||
|
Employee
benefits
|
87 | 80 | ||||||
|
Loss
and credit carryforwards
|
24 | 8 | ||||||
|
Regulatory
liabilities, net
|
— | 11 | ||||||
|
Other
|
24 | 11 | ||||||
|
Total
non-current deferred tax assets before valuation allowance
|
135 | 110 | ||||||
|
Valuation
allowance
|
(18 | ) | (5 | ) | ||||
|
Total
non-current deferred tax assets
|
117 | 105 | ||||||
|
Total
deferred tax assets, net
|
159 | 130 | ||||||
|
Deferred
tax liabilities:
|
||||||||
|
Current:
|
||||||||
|
Non-trading
derivative liabilities, net
|
$ | 2 | $ | — | ||||
|
Non-current:
|
||||||||
|
Depreciation
|
851 | 927 | ||||||
|
Regulatory
assets, net
|
16 | — | ||||||
|
Other
|
28 | 42 | ||||||
|
Total
non-current deferred tax liabilities
|
895 | 969 | ||||||
|
Total
deferred tax liabilities
|
897 | 969 | ||||||
|
Accumulated
deferred income taxes, net
|
$ | 738 | $ | 839 | ||||
The
Company is included in the consolidated income tax returns of CenterPoint
Energy. The Company calculates its income tax provision on a separate return
basis under a tax sharing agreement with CenterPoint Energy.
Tax Attribute Carryforwards and
Valuation Allowance. At December 31, 2008, the Company
has approximately $128 million of state net operating loss carryforwards
which expire in various years between 2009 and 2028. A valuation allowance has
been established for approximately $60 million of the state net operating
loss carryforwards that may not be realized. The Company has a state tax credit
carryforward of approximately $3 million which expires in 2026. At
December 31, 2008, the Company has approximately $244 million of state
capital loss carryforwards which expire in 2017 for which a full valuation
allowance was established in prior periods. A re-measurement of the deferred tax
asset arising from the state capital loss carryforward caused a decrease equal
to $12 million in both the deferred tax asset and the associated valuation
allowance. The change did not impact the effective income tax rate.
Uncertain Income Tax
Positions. The Company adopted the provisions of FIN 48 on January 1,
2007. The cumulative effect of adopting FIN 48 as of January 1, 2007 was a
credit to retained earnings of less than $1 million. A reconciliation of the
change in unrecognized tax benefits for 2007 and 2008 is as
follows:
|
December 31,
|
||||||||
|
2007
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Balance,
beginning of year
|
$ | 1 | $ | (11 | ) | |||
|
Tax
Positions related to prior years:
|
||||||||
|
Reductions
|
(10 | ) | (1 | ) | ||||
|
Settlements
|
(2 | ) | — | |||||
|
Balance,
end of year
|
$ | (11 | ) | $ | (12 | ) | ||
The
Company has approximately $1 million of unrecognized tax benefits that, if
recognized, would reduce the effective income tax rate for both 2007 and 2008.
The Company recognizes interest and penalties as a component of income tax
expense. The Company recognized approximately $3 million and $1 million of
benefit for interest on uncertain income tax positions during 2007 and 2008,
respectively. The Company accrued $3 million and $4 million of interest
receivable on uncertain income tax positions at December 31, 2007 and 2008,
respectively. The Company does not expect the amount of unrecognized tax
benefits to change significantly over the next 12 months.
Tax Audits and
Settlements. CenterPoint Energy’s consolidated federal income
tax returns have been audited and settled through the 2003 tax year and the
Internal Revenue Service (IRS) is currently at various stages of the examination
process for tax years 2004 through 2007. The Company has considered the effects
of these examinations in its accrual for settled issues and liability for
uncertain income tax positions as of December 31, 2008.
CenterPoint
Energy reached a tentative settlement with the IRS for a number of tax issues in
the fourth quarter of 2006, resulting in a reduction in the Company’s income tax
expense for 2006 of approximately $20 million.
|
9.
|
Commitments
and Contingencies
|
(a) Natural
Gas Supply Commitments
Natural
gas supply commitments include natural gas contracts related to the Company’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 the Company’s
Consolidated Balance Sheets as of December 31, 2007 and December 31,
2008 as these contracts meet the SFAS No. 133 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, 2008,
minimum payment obligations for natural gas supply commitments are approximately
$776 million in 2009, $474 million in 2010, $437 million in 2011,
$430 million in 2012, $447 million in 2013 and $956 million in
2014 and thereafter.
(b) Lease
Commitments
The
following table sets forth information concerning the Company’s obligations
under non-cancelable long-term operating leases at December 31, 2008, which
primarily consist of rental agreements for building space, data processing
equipment and vehicles, including major work equipment (in
millions):
|
2009
|
$ | 14 | ||
|
2010
|
11 | |||
|
2011
|
11 | |||
|
2012
|
7 | |||
|
2013
|
6 | |||
|
2014
and beyond
|
25 | |||
|
Total
|
$ | 74 |
Total
rental expense for all operating leases was $51 million, $43 million
and $41 million in 2006, 2007 and 2008, respectively.
(c) Capital
Commitments
In 2007,
CenterPoint Energy Gas Transmission Company (CEGT) completed phases one and two
of its Carthage to Perryville pipeline project with a total capacity of
1.25 billion cubic feet (Bcf) per day. In 2008, CEGT completed
the Phase III expansion of the Carthage to Perryville pipeline which increased
total capacity to 1.5 Bcf per day. During the four-year period subsequent to the
in-service date of the pipeline, XTO Energy, CEGT’s anchor shipper, can request,
and subject to mutual negotiations that meet specific financial parameters and
to Federal Energy Regulatory Commission (FERC) approval, CEGT would construct a
67-mile extension from CEGT’s Perryville hub to an interconnect with Texas
Eastern Gas Transmission at Union Church, Mississippi. CEGT
filed
59
with FERC
on December 5, 2008 to increase the Carthage to Perryville capacity to
approximately 1.9 Bcf per day. The expansion includes a new compressor
unit at two of CEGT’s existing stations and is currently projected to be placed
in service in the second quarter of 2010.
(d) Legal,
Environmental and Other Matters
Legal
Matters
RRI
Indemnified Litigation
CenterPoint
Energy or its predecessor, Reliant Energy, Incorporated (Reliant Energy), and
certain of their present or former subsidiaries are named as defendants in
several lawsuits described below. Under a master separation agreement between
CenterPoint Energy and Reliant Energy, Inc. (formerly Reliant Resources, Inc.)
(RRI), CenterPoint Energy and its subsidiaries, including the
Company, are entitled to be indemnified by RRI for any losses,
including attorneys’ fees and other costs, arising out of the lawsuits described
below under “Gas Market Manipulation Cases.” Pursuant to the indemnification
obligation, RRI is defending CenterPoint Energy and its subsidiaries to the
extent named in these lawsuits. Although the ultimate outcome of these matters
cannot be predicted at this time, CenterPoint Energy has not considered it
necessary to establish reserves related to this litigation.
Gas Market Manipulation
Cases. 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 2000-2001. 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 2007.
In October 2006, RRI reached a settlement of 11 class action natural gas cases
pending in state court in California. The court approved this settlement in June
2007. In the other gas cases consolidated in state court in California, the
Court of Appeals found that CenterPoint Energy was not a successor to the
liabilities of a subsidiary of RRI, and CenterPoint Energy was dismissed from
these suits in April 2008. In the Nevada federal litigation, three of the
complaints were dismissed based on defendants’ filed rate doctrine defense, but
the Ninth Circuit Court of Appeals reversed those dismissals and remanded the
cases back to the district court for further proceedings. In July
2008, the plaintiffs in four of the federal court cases agreed to dismiss
CenterPoint Energy from those cases. In August 2008, the plaintiffs in five
additional cases also agreed to dismiss CenterPoint Energy from those cases, but
one of these plaintiffs has moved to amend its complaint to add CenterPoint
Energy Services, Inc., a subsidiary of CERC Corp., as a defendant in that
case. As a result, CenterPoint Energy remains a party in only two
remaining gas market manipulation cases, one pending in Nevada state court in
Clark County and one in federal district court in Nevada. CenterPoint
Energy believes it is not a proper defendant in the remaining cases and will
continue to pursue dismissal from those cases.
Natural Gas Measurement
Lawsuits. CERC Corp. and certain of its subsidiaries are 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 seeks
undisclosed damages, along with statutory penalties, interest, costs and fees.
The complaint is part of a larger series of complaints filed against 77 natural
gas pipelines and their subsidiaries and affiliates. An earlier single action
making substantially similar allegations against the pipelines was dismissed by
the federal district court for the District of Columbia on grounds of improper
joinder and lack of jurisdiction. As a result, the various individual complaints
were filed in numerous courts throughout the country. This case has been
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 has sought review of that dismissal from the Tenth
Circuit Court of Appeals, where the matter remains pending.
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
60
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. The Company
believes that there has been no systematic mismeasurement of gas and that the
lawsuits are without merit. The Company does not expect the ultimate outcome of
the lawsuits to have a material impact on its financial condition, results of
operations or cash flows.
Gas Cost Recovery Litigation.
In October 2002, a lawsuit was filed on behalf of certain ratepayers of
the Company in state district court in Wharton County, Texas against the
Company, CenterPoint Energy, Entex Gas Marketing Company (EGMC), and certain
non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade
Practices Act, violations of the Texas Utilities Code, civil conspiracy and
violations of the Texas Free Enterprise and Antitrust Act with respect to rates
charged to certain consumers of natural gas in the State of Texas. The
plaintiffs initially sought certification of a class of Texas ratepayers, but
subsequently dropped their request for class certification. The plaintiffs later
added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy
Pipeline Services, Inc. (CEPS), and certain other subsidiaries of the Company,
and other non-affiliated companies. In February 2005, the case was removed to
federal district court in Houston, Texas, and in March 2005, the plaintiffs
voluntarily dismissed the case and agreed not to refile the claims asserted
unless the Miller County case described below is not certified as a class action
or is later decertified.
In
October 2004, a lawsuit was filed by certain ratepayers of the Company in Texas
and Arkansas in circuit court in Miller County, Arkansas against CERC Corp.,
CenterPoint Energy, EGMC, CEGT, CenterPoint Energy Field Services (CEFS), CEPS,
Mississippi River Transmission Corp. (MRT) 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. Subsequently, the plaintiffs dropped CEGT and
MRT as defendants. 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). In response to
that ruling, in August 2007 the Miller County court stayed but refused to
dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court
directed the Miller County court to dismiss the entire case for lack of
jurisdiction. The Miller County court subsequently dismissed the case in
accordance with the Arkansas Supreme Court’s mandate and all appellate deadlines
have expired.
In June
2007, CERC Corp., CenterPoint Energy, EGMC 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 October 2007, CEFS
and CEPS joined the petition in the Travis County case. In October
2008, the district court ruled that the Railroad Commission had exclusive
original jurisdiction over the Texas claims asserted against CERC Corp.,
CenterPoint Energy, EGMC and the other defendants in the Miller County
case. In January 2009, the court entered a final declaratory judgment
ruling that the Railroad Commission has exclusive jurisdiction over Texas
claims. The Company does not anticipate that an appeal will be
filed.
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 the Company. In
February 2009, the Arkansas plaintiff notified the APSC that he would no longer
pursue his claims. That complaint remains pending at the APSC, subject to the
review of the Arkansas Attorney General, APSC Staff and the APSC.
In
February 2003, a lawsuit was filed in state court in Caddo Parish, Louisiana
against the Company with respect to rates charged to a purported class of
certain consumers of natural gas and gas service in the State of Louisiana. In
February 2004, another suit was filed in state court in Calcasieu Parish,
Louisiana against the Company seeking to
61
recover
alleged overcharges for gas or gas services allegedly provided by the Company to
a purported class of certain consumers of natural gas and gas service without
advance approval by the Louisiana Public Service Commission (LPSC). At the time
of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in
those cases filed petitions with the LPSC relating to the same alleged rate
overcharges. The Caddo and Calcasieu Parish lawsuits were stayed pending the
resolution of the petitions filed with the LPSC. In August 2007, the LPSC issued
an order approving a Stipulated Settlement in the review initiated by the
plaintiffs in the Calcasieu Parish litigation. In the LPSC proceeding, the
Company’s gas purchases were reviewed back to 1971. The review concluded that
the Company’s gas costs were “reasonable and prudent,” but the Company agreed to
credit to jurisdictional customers approximately $920,000, including interest,
related to certain off-system sales. The refund was completed in the fourth
quarter of 2008. A similar review by the LPSC related to the Caddo Parish
litigation was resolved without additional payment by the Company. In October
2008, the courts considering the Caddo and Calcasieu Parish cases dismissed
these cases pursuant to motions to dismiss and these proceedings have been
concluded.
Storage Facility Litigation.
In February 2007, an Oklahoma district court in Coal County, Oklahoma, granted a
summary judgment against CEGT in a case, Deka Exploration, Inc. v. CenterPoint
Energy, filed by holders of oil and gas leaseholds and some mineral interest
owners in lands underlying CEGT’s Chiles Dome Storage Facility. The dispute
concerns “native gas” that may have been in the Wapanucka formation underlying
the Chiles Dome facility when that facility was constructed in 1979 by an entity
of the Company that was the predecessor in interest of CEGT. The court ruled
that the plaintiffs own native gas underlying those lands, since neither CEGT
nor its predecessors had condemned those ownership interests. The court rejected
CEGT’s contention that the claim should be barred by the statute of limitations,
since the suit was filed over 25 years after the facility was constructed. The
court also rejected CEGT’s contention that the suit is an impermissible attack
on the determinations the FERC and Oklahoma Corporation Commission made
regarding the absence of native gas in the lands when the facility was
constructed. The summary judgment ruling was only on the issue of liability,
though the court did rule that CEGT has the burden of proving that any gas in
the Wapanucka formation is gas that has been injected and is not native gas.
Further hearings and orders of the court are required to specify the appropriate
relief for the plaintiffs. CEGT plans to appeal through the Oklahoma court
system any judgment that imposes liability on CEGT in this matter. The Company
does not expect the outcome of this matter to have a material impact on its
financial condition, results of operations or cash flows.
Environmental
Matters
Manufactured Gas Plant Sites.
The Company and its predecessors operated manufactured gas plants (MGPs) in the
past. In Minnesota, the Company has completed remediation on two sites, other
than ongoing monitoring and water treatment. There are five remaining sites in
the Company’s Minnesota service territory. The Company believes that it has no
liability with respect to two of these sites.
At
December 31, 2008, the Company 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. The Company 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, 2008, the Company had collected
$13 million from insurance companies and rate payers to be used for future
environmental remediation.
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 the Company or may have been owned by one of its former affiliates.
The Company 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 the Company or its divisions.
The Company 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 is required to determine
if other potentially responsible parties, including the Company, would have to
contribute to that remediation. The Company is investigating details regarding
the site and
62
the range
of environmental expenditures for potential remediation. However, the Company
believes it is not liable as a former owner or operator of the site under the
Comprehensive Environmental, Response, Compensation and Liability Act of 1980,
as amended, and applicable state statutes, and is vigorously contesting the suit
and its designation as a PRP.
Mercury Contamination. The
Company’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. The Company has found
this type of contamination at some sites in the past, and the Company 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 the
Company’s experience and that of others in the natural gas industry to date and
on the current regulations regarding remediation of these sites, the Company
believes that the costs of any remediation of these sites will not be material
to the Company’s financial condition, results of operations or cash
flows.
Asbestos. Some
facilities formerly owned by the Company’s predecessors have contained asbestos
insulation and other asbestos-containing materials. The Company or its
predecessor companies have been named, along with numerous others, as a
defendant in lawsuits filed by certain individuals who claim injury due to
exposure to asbestos during work at such formerly owned facilities. The Company
anticipates that additional claims like those received may be asserted in the
future. Although their ultimate outcome cannot be predicted at this
time, the Company 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 the Company’s financial condition, results of operations or
cash flows.
Groundwater Contamination
Litigation. Predecessor entities of the Company, 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 the Company held an interest in two oil and gas leases on a
portion of the property at issue, neither it nor any other entities of the
Company drilled or conducted other oil and gas operations on those
leases. In January 2009, the Company and the plaintiffs reached
agreement on the terms of a settlement that, if ultimately approved by the
Louisiana Department of Natural Resources and the court, is expected to finally
resolve this litigation. The Company does not expect the outcome of
this litigation to have a material adverse impact on its financial condition,
results of operations or cash flows.
Other
Environmental. From time to time the Company 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, the Company 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, the Company does not
expect, based on its experience to date, these matters, either individually or
in the aggregate, to have a material adverse effect on the Company’s financial
condition, results of operations or cash flows.
Other
Proceedings
The
Company 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. The Company regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. The Company does not
expect the disposition of these matters to have a material adverse effect on the
Company’s financial condition, results of operations or cash flows.
Guaranties
Prior to
CenterPoint Energy’s distribution of its ownership in RRI to its shareholders,
the Company had guaranteed certain contractual obligations of what became RRI’s
trading subsidiary. Under the terms of the
63
separation
agreement between the companies, RRI agreed to extinguish all such guaranty
obligations prior to separation, but at the time of separation in September
2002, RRI had been unable to extinguish all obligations. To secure the Company
against obligations under the remaining guaranties, RRI agreed to provide cash
or letters of credit for the Company’s benefit, and undertook to use
commercially reasonable efforts to extinguish the remaining guaranties. In
December 2007, the Company, CenterPoint Energy and RRI amended that agreement
and the Company released the letters of credit it held as security. Under the
revised agreement RRI agreed to provide cash or new letters of credit to secure
the Company against exposure under the remaining guaranties as calculated under
the revised agreement if and to the extent changes in market conditions exposed
the Company to a risk of loss on those guaranties.
The
potential exposure to the Company under the guaranties relates to payment of
demand charges related to transportation contracts. The present value of the
demand charges under these transportation contracts, which will be effective
until 2018, was approximately $108 million as of December 31, 2008. RRI
continues to meet its obligations under the contracts, and, on the basis of
market conditions, the Company and CenterPoint Energy have not required
additional security. However, if RRI should fail to perform its obligations
under the contracts or if RRI should fail to provide adequate security in the
event market conditions change adversely, the Company would retain exposure to
the counterparty under the guaranty.
|
10.
|
Estimated
Fair Value of Financial Instruments
|
The fair
values of cash and cash equivalents 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
are equivalent to their carrying amounts in the Consolidated Balance Sheets at
December 31, 2007 and 2008 and have been determined using quoted market
prices for the same or similar instruments when available or other estimation
techniques (see Note 5). Therefore, these financial instruments are stated at
fair value and are excluded from the table below.
|
December 31,
2007
|
December 31,
2008
|
|||||||||||||||
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Financial
liabilities:
|
||||||||||||||||
|
Long-term
debt
|
$ | 2,952 | $ | 3,079 | $ | 3,719 | $ | 3,568 | ||||||||
|
11.
|
Unaudited
Quarterly Information
|
Summarized
quarterly financial data is as follows:
|
Year
Ended December 31, 2007
|
||||||||||||||||
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Revenues
|
$ | 2,697 | $ | 1,566 | $ | 1,351 | $ | 2,162 | ||||||||
|
Operating
income
|
250 | 83 | 91 | 202 | ||||||||||||
|
Net
income
|
131 | 30 | 28 | 98 | ||||||||||||
|
Year
Ended December 31, 2008
|
||||||||||||||||
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Revenues
|
$ | 2,952 | $ | 2,157 | $ | 1,960 | $ | 2,326 | ||||||||
|
Operating
income
|
242 | 130 | 129 | 216 | ||||||||||||
|
Net
income
|
126 | 60 | 67 | 90 | ||||||||||||
|
12.
|
Reportable
Business Segments
|
Because
the Company is an indirect wholly owned subsidiary of CenterPoint Energy, the
Company’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
64
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. The Company uses operating income as
the measure of profit or loss for its business segments.
The
Company’s reportable business segments include the following: Natural Gas
Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines,
Field Services and Other Operations. Natural Gas Distribution consists of
rate-regulated 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 the Company’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 operations. Our Other Operations business
segment includes unallocated corporate costs and inter-segment
eliminations.
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
|
Inter-segment
Revenues
|
Depreciation
and
Amortization
|
Operating
Income
(Loss)
|
Total
Assets
|
Expenditures
for
Long-
Lived
Assets
|
|||||||||||||||||||
|
As
of and for the year ended December 31, 2006:
|
||||||||||||||||||||||||
|
Natural
Gas Distribution
|
$ | 3,582 | $ | 11 | $ | 152 | $ | 124 | $ | 4,463 | $ | 187 | ||||||||||||
|
Competitive
Natural Gas Sales and Services
|
3,572 | 79 | 1 | 77 | 1,501 | 18 | ||||||||||||||||||
|
Interstate
Pipelines (1)
|
255 | 133 | 37 | 181 | 2,738 | 437 | ||||||||||||||||||
|
Field
Services (2)
|
119 | 31 | 10 | 89 | 608 | 65 | ||||||||||||||||||
|
Other
|
— | 5 | — | 1 | 1,086 | — | ||||||||||||||||||
|
Reconciling
Eliminations
|
— | (259 | ) | — | — | (1,581 | ) | — | ||||||||||||||||
|
Consolidated
|
$ | 7,528 | $ | — | $ | 200 | $ | 472 | $ | 8,815 | $ | 707 | ||||||||||||
|
As
of and for the year ended December 31, 2007:
|
||||||||||||||||||||||||
|
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 (1)
|
357 | 143 | 44 | 237 | 3,007 | 308 | ||||||||||||||||||
|
Field
Services (2)
|
136 | 39 | 11 | 99 | 669 | 74 | ||||||||||||||||||
|
Other
|
— | — | — | (3 | ) | 670 | — | |||||||||||||||||
|
Reconciling
Eliminations
|
— | (237 | ) | — | — | (765 | ) | — | ||||||||||||||||
|
Consolidated
|
$ | 7,776 | $ | — | $ | 215 | $ | 626 | $ | 9,134 | $ | 580 | ||||||||||||
|
As
of and for the year ended December 31, 2008:
|
||||||||||||||||||||||||
|
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 (1)
|
477 | 173 | 46 | 293 | 3,578 | 189 | ||||||||||||||||||
|
Field
Services (2)
|
213 | 39 | 12 | 147 | 826 | 122 | ||||||||||||||||||
|
Other
|
— | — | — | — | 724 | — | ||||||||||||||||||
|
Reconciling
Eliminations
|
— | (261 | ) | — | — | (1,193 | ) | — | ||||||||||||||||
|
Consolidated
|
$ | 9,395 | $ | — | $ | 218 | $ | 717 | $ | 10,211 | $ | 533 | ||||||||||||
|
(1)
|
Interstate
Pipelines recorded equity income of $6 million and $36 million
(including $6 million and $33 million related to pre-operating
allowance for funds used during construction) in the years ended December
31, 2007 and 2008, respectively, from its 50 percent 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
$8 million, $58 million and $307 million as of December 31,
2006, 2007 and 2008 and is included in Investment in unconsolidated
affiliates.
|
|
(2)
|
Field
Services recorded equity income of $6 million, $10 million and
$15 million for the years ended December 31, 2006, 2007 and
2008, respectively, from its 50 percent 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 $24 million, $30 million and
$38 million as of December 31, 2006, 2007 and 2008 and is included in
Investment in unconsolidated
affiliates.
|
|
Year
Ended December 31,
|
||||||||||||
|
Revenues
by Products and Services:
|
2006
|
2007
|
2008
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Retail
gas sales
|
4,546 | 4,941 | 6,216 | |||||||||
|
Wholesale
gas sales
|
2,331 | 2,196 | 2,295 | |||||||||
|
Gas
transport
|
550 | 532 | 756 | |||||||||
|
Energy
products and services
|
101 | 107 | 128 | |||||||||
|
Total
|
$ | 7,528 | $ | 7,776 | $ | 9,395 | ||||||
None.
Item
9A(T). 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, 2008 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, 2008 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.
Item
9B. Other
Information
None.
PART III
Item
10. Directors, Executive
Officers and Corporate Governance
The
information called for by Item 10 is omitted pursuant to Instruction I(2) to
Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
Item
11. Executive
Compensation
The
information called for by Item 11 is omitted pursuant to Instruction I(2) to
Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
Item
12. Security Ownership of
Certain Beneficial Owners and Management and Related Stockholder
Matters
The information called for by Item 12 is omitted pursuant to Instruction I(2) to
Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
Item
13. Certain Relationships
and Related Transactions, and Director Independence
The
information called for by Item 13 is omitted pursuant to Instruction I(2) to
Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
Item
14. Principal Accounting
Fees and Services
Aggregate
fees billed to the Company during the fiscal years ending December 31, 2007
and 2008 by its principal accounting firm, Deloitte & Touche LLP, are set
forth below.
|
Year
Ended December 31,
|
||||||||
|
2007
|
2008
|
|||||||
|
Audit
fees
(1)
|
$ | 1,205,900 | $ | 1,199,800 | ||||
|
Audit-related
fees
(2)
|
93,720 | 86,869 | ||||||
|
Total
audit and audit-related fees
|
1,299,620 | 1,286,669 | ||||||
|
Tax
fees
|
— | — | ||||||
|
All
other
fees
|
— | — | ||||||
|
Total
fees
|
$ | 1,299,620 | $ | 1,286,669 | ||||
____________
|
(1)
|
For
2008 and 2007, amounts include fees for services provided by the principal
accounting firm relating to the integrated audit of financial statements
and internal control over financial reporting, statutory audits, attest
services, and regulatory filings.
|
|
(2)
|
For
2008 and 2007, includes fees for consultations concerning financial
accounting and reporting standards and various agreed-upon or expanded
procedures related to accounting records to comply with financial
accounting or regulatory reporting
matters.
|
The
Company is not required to have, and does not have, an audit
committee.
PART IV
Item
15. Exhibits and
Financial Statement Schedules
|
(a)(1)
Financial Statements.
|
|
|
35
|
|
|
37
|
|
|
38
|
|
|
39
|
|
|
40
|
|
|
41
|
|
|
42
|
|
|
(a)(2)
Financial Statement Schedules for the Three Years Ended December 31,
2008.
|
|
|
69
|
|
|
70
|
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:
I, III,
IV and V.
(a)(3)
Exhibits.
See Index
of Exhibits beginning on page 71.
To the
Stockholder of
CenterPoint
Energy Resources Corp.
Houston,
Texas
We have
audited the consolidated financial statements of CenterPoint Energy Resources
Corp. and subsidiaries (the “Company”, an indirect wholly owned subsidiary of
CenterPoint Energy, Inc.) as of December 31, 2008 and 2007, and for each of the
three years in the period ended December 31, 2008, and have issued our report
thereon dated March 11, 2009; such report is included elsewhere in this Form
10-K. Our audits also included the consolidated financial statement
schedule of the Company listed in the
index at Item 15(a)(2). This consolidated financial statement schedule is
the responsibility of the Company's management. Our responsibility is to
express an opinion based on our audits. In our opinion, such consolidated
financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.
DELOITTE
& TOUCHE LLP
Houston,
Texas
March 11,
2009
(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
SCHEDULE
II — QUALIFYING VALUATION ACCOUNTS
For
the Three Years Ended December 31, 2008
|
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
(1)
|
|||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
Year
Ended December 31, 2008:
|
||||||||||||||||||||
|
Accumulated
provisions:
|
||||||||||||||||||||
|
Uncollectible
accounts receivable
|
$ | 37 | $ | 53 | $ | 3 | $ | 60 | $ | 33 | ||||||||||
|
Deferred
tax asset valuation allowance
|
18 | (1 | ) | (12 | ) | — | 5 | |||||||||||||
|
Year
Ended December 31, 2007:
|
||||||||||||||||||||
|
Accumulated
provisions:
|
||||||||||||||||||||
|
Uncollectible
accounts receivable
|
32 | 42 | — | 37 | 37 | |||||||||||||||
|
Deferred
tax asset valuation allowance
|
22 | (4 | ) | — | — | 18 | ||||||||||||||
|
Year
Ended December 31, 2006:
|
||||||||||||||||||||
|
Accumulated
provisions:
|
||||||||||||||||||||
|
Uncollectible
accounts receivable
|
38 | 37 | — | 43 | 32 | |||||||||||||||
|
Deferred
tax asset valuation allowance
|
21 | 1 | — | — | 22 | |||||||||||||||
|
(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 11th day of March, 2009.
|
CENTERPOINT
ENERGY RESOURCES CORP.
|
|
|
(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 March 11, 2009.
|
Signature
|
Title
|
|
|
/s/
DAVID M. MCCLANAHAN
|
Chairman,
President and Chief Executive Officer
|
|
|
(David
M. McClanahan)
|
(Principal
Executive Officer and Director)
|
|
|
/s/
GARY L. WHITLOCK
|
Executive
Vice President and Chief Financial Officer
|
|
|
(Gary
L. Whitlock)
|
(Principal
Financial Officer)
|
|
|
/s/
WALTER L. FITZGERALD
|
Senior
Vice President and Chief Accounting Officer
|
|
|
(Walter
L. Fitzgerald)
|
(Principal
Accounting Officer)
|
|
CENTERPOINT
ENERGY RESOURCES CORP. AND SUBSIDIARIES
EXHIBITS
TO THE ANNUAL REPORT ON FORM 10-K
For
Fiscal Year Ended December 31, 2008
INDEX
OF EXHIBITS
Exhibits
not incorporated by reference to a prior filing are designated by a cross (+);
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.
|
Exhibit
Number
|
Description
|
Report
or
Registration
Statement
|
SEC
File or
Registration
Number
|
Exhibit
Reference
|
||||
|
2(a)(1)
|
Agreement
and Plan of Merger among the Company, Houston Lighting and Power Company
(“HL&P”), HI Merger, Inc. and NorAm Energy Corp. (“NorAm”) dated
August 11, 1996
|
Houston
Industries’ (“HI’s”) Form 8-K dated August 11, 1996
|
1-7629
|
2
|
||||
|
2(a)(2)
|
Amendment
to Agreement and Plan of Merger among the Company, HL&P, HI Merger,
Inc. and NorAm dated August 11, 1996
|
Registration
Statement on Form S-4
|
333-11329
|
2(c)
|
||||
|
2(b)
|
Agreement
and Plan of Merger dated December 29, 2000 merging Reliant Resources
Merger Sub, Inc. with and into Reliant Energy Services, Inc.
|
Registration
Statement on Form S-3
|
333-54526
|
2
|
||||
|
3(a)(1)
|
Certificate
of Incorporation of Reliant Energy Resources Corp. (“RERC
Corp.”)
|
Form
10-K for the year ended December 31, 1997
|
1-3187
|
3(a)(1)
|
||||
|
3(a)(2)
|
Certificate
of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc.
dated August 6, 1997
|
Form
10-K for the year ended December 31, 1997
|
1-3187
|
3(a)(2)
|
||||
|
3(a)(3)
|
Certificate
of Amendment changing the name to Reliant Energy Resources
Corp.
|
Form
10-K for the year ended December 31, 1998
|
1-3187
|
3(a)(3)
|
||||
|
3(a)(4)
|
Certificate
of Amendment changing the name to CenterPoint Energy Resources
Corp.
|
Form
10-Q for the quarter ended June 30, 2003
|
1-13265
|
3(a)(4)
|
||||
|
3(b)
|
Bylaws
of RERC Corp.
|
Form
10-K for the year ended December 31, 1997
|
1-3187
|
3(b)
|
||||
|
4(a)(1)
|
Indenture,
dated as of March 31, 1987, between NorAm and Chase Manhattan
Bank, N.A., as Trustee, authorizing 6% Convertible Subordinated Debentures
due 2012
|
NorAm’s
Registration Statement on Form S-3
|
33-14586
|
4.20
|
||||
|
4(a)(2)
|
Supplemental
Indenture to Exhibit 4(a)(1) dated as of
August 6, 1997
|
Form
10-K for the year ended December 31, 1997
|
1-3187
|
4(b)(2)
|
|
Exhibit
Number
|
Description
|
Report
or
Registration
Statement
|
SEC
File or
Registration
Number
|
Exhibit
Reference
|
||||
|
4(b)(1)
|
Indenture,
dated as of February 1, 1998, between RERC Corp. and Chase Bank
of Texas, National Association, as Trustee
|
Form
8-K dated February 5, 1998
|
1-13265
|
4.1
|
||||
|
4(b)(2)
|
Supplemental
Indenture No. 1, dated as of February 1, 1998, providing
for the issuance of RERC Corp.’s 6 1/2%
Debentures
due February 1, 2008
|
Form
8-K dated February 5, 1998
|
1-13265
|
4.2
|
||||
|
4(b)(3)
|
Supplemental
Indenture No. 2, dated as of November 1, 1998, providing
for the issuance of RERC Corp.’s 6 3/8% Term Enhanced ReMarketable
Securities
|
Form
8-K dated November 9, 1998
|
1-13265
|
4.1
|
||||
|
4(b)(4)
|
Supplemental
Indenture No. 3, dated as of July 1, 2000, providing for
the issuance of RERC Corp.’s 8.125% Notes due 2005
|
Registration
Statement on Form S-4
|
333-49162
|
4.2
|
||||
|
4(b)(5)
|
Supplemental
Indenture No. 4, dated as of February 15, 2001, providing
for the issuance of RERC Corp.’s 7.75% Notes due 2011
|
Form
8-K dated February 21, 2001
|
1-13265
|
4.1
|
||||
|
4(b)(6)
|
Supplemental
Indenture No. 5, dated as of March 25, 2003, providing for
the issuance of CERC Corp.’s 7.875% Senior Notes due 2013
|
Form
8-K dated March 18, 2003
|
1-13265
|
4.1
|
||||
|
4(b)(7)
|
Supplemental
Indenture No. 6, dated as of April 14, 2003, providing for
the issuance of CERC Corp.’s 7.875% Senior Notes due 2013
|
Form
8-K dated April 7, 2003
|
1-13265
|
4.2
|
||||
|
4(b)(8)
|
Supplemental
Indenture No. 7, dated as of November 3, 2003, providing
for the issuance of CERC Corp.’s 5.95% Senior Notes due 2014
|
Form
8-K dated October 29, 2003
|
1-13265
|
4.2
|
||||
|
4(b)(9)
|
Supplemental
Indenture No. 8, dated as of December 28, 2005, providing
for the issuance of CERC Corp.’s 6 1/2% Debentures due 2008
|
CenterPoint
Energy, Inc.’s (“CNP’s”) Form 10-K for the year ended
December 31, 2005
|
1-31447
|
4(f)(9)
|
||||
|
4(b)(10)
|
Supplemental
Indenture No. 9, dated as of May 18, 2006, providing for
the issuance of CERC Corp.’s 6.15% Senior Notes due 2016
|
CNP’s
Form 10-Q for the quarter ended June 30, 2006
|
1-31447
|
4.7
|
||||
|
4(b)(11)
|
Supplemental
Indenture No. 10, dated as of February 6, 2007, providing
for the issuance of CERC Corp.’s 6.25% Senior Notes due 2037
|
CNP’s
Form 10-K for the year ended December 31, 2007
|
1-31447
|
4(f)(11)
|
||||
|
4(b)(12)
|
Supplemental
Indenture No. 11 dated as of October 23, 2007, providing
for the issuance of CERC Corp.’s 6.125% Senior Notes due
2017
|
CNP’s
Form 10-Q for quarter ended September 30, 2007
|
1-31447
|
4.8
|
|
Exhibit
Number
|
Description
|
Report
or
Registration
Statement
|
SEC
File or
Registration
Number
|
Exhibit
Reference
|
||||
|
4(b)(13)
|
Supplemental
Indenture No. 12 dated as of October 23, 2007,
providing for the issuance of CERC Corp.’s 6.625% Senior Notes due
2037
|
CNP’s
Form 10-Q for quarter ended September 30, 2007
|
1-31447
|
4.9
|
||||
|
4(b)(14)
|
Supplemental
Indenture No. 13 dated as of May 15, 2008, providing for
the issuance of CERC Corp.’s 6.00% Senior Notes due 2018
|
CNP’s
Form 10-Q for quarter ended June 30, 2008
|
1-31447
|
4.9
|
||||
|
4(c)
|
$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
|
CNP’s
Form 10-Q for the quarter ended June 30, 2007
|
1-31447
|
4.5
|
There
have not been filed as exhibits to this Form 10-K certain long-term debt
instruments, including indentures, under which the total amount of securities do
not exceed 10% of the total assets of CERC. CERC 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)
|
Service
Agreement by and between Mississippi River Transmission Corporation and
Laclede Gas Company dated August 22, 1989
|
NorAm’s
Form 10-K for the year ended December 31, 1989
|
1-13265
|
10.20
|
||||
|
+12
|
|
|||||||
|
+23
|
|
|||||||
|
+31.1
|
|
|||||||
|
+31.2
|
|
|||||||
|
+32.1
|
|
|||||||
|
+32.2
|
|
74
Exhibit
12
CENTERPOINT
ENERGY RESOURCES CORP. AND SUBSIDIARIES
(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)
COMPUTATION
OF RATIOS OF EARNINGS TO FIXED CHARGES
(millions
of dollars)
|
Year
Ended December 31,
|
||||||||||||||||||||
|
2004
|
2005
|
2006
|
2007
(1)
|
2008
(1)
|
||||||||||||||||
|
Net
Income
|
$ | 144 | $ | 193 | $ | 207 | $ | 287 | $ | 343 | ||||||||||
|
Income
taxes
|
87 | 116 | 116 | 173 | 228 | |||||||||||||||
|
Capitalized
interest
|
(2 | ) | (1 | ) | (6 | ) | (12 | ) | (14 | ) | ||||||||||
| 229 | 308 | 317 | 448 | 557 | ||||||||||||||||
|
Fixed
charges, as defined:
|
||||||||||||||||||||
|
Interest expense
|
178 | 176 | 167 | 187 | 213 | |||||||||||||||
|
Capitalized
interest
|
2 | 1 | 6 | 12 | 14 | |||||||||||||||
|
Interest component of rentals
charged
to operating expense
|
10 | 11 | 17 | 14 | 13 | |||||||||||||||
|
Total fixed
charges
|
190 | 188 | 190 | 213 | 240 | |||||||||||||||
|
Earnings,
as defined
|
$ | 419 | $ | 496 | $ | 507 | $ | 661 | $ | 797 | ||||||||||
|
Ratio
of earnings to fixed charges
|
2.20 | 2.64 | 2.67 | 3.10 | 3.32 | |||||||||||||||
________
|
|
(1)
|
Excluded
from the computation of fixed charges for the years ended December 31,
2007 and 2008 is interest income of $2 million and $1 million,
respectively, which is included in income tax
expense.
|
Exhibit
23
CONSENT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We
consent to the incorporation by reference in Registration Statement No.
333-153052 on Form S-3 of our reports dated March 11, 2009, relating to the
consolidated financial statements and consolidated financial statement schedule
of CenterPoint Energy Resources Corp. and subsidiaries appearing in
this Annual Report on Form 10-K of CenterPoint Energy Resources Corp. for the
year ended December 31, 2008.
DELOITTE
& TOUCHE LLP
Houston,
Texas
March 11,
2009
Exhibit
31.1
CERTIFICATIONS
I, David
M. McClanahan, certify that:
1. I
have reviewed this annual report on Form 10-K of CenterPoint Energy Resources
Corp.;
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: March
11, 2009
|
/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 Resources
Corp.;
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: March
11, 2009
|
/s/
Gary L. Whitlock
|
|
|
Gary
L. Whitlock
|
|
|
Executive
Vice President and Chief Financial
Officer
|
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 Resources Corp. (the “Company”) on Form 10-K for the year
ended December 31, 2008 (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.
|
/s/
David M. McClanahan
|
|
|
David
M. McClanahan
|
|
|
President
and Chief Executive Officer
|
|
|
March 11,
2009
|
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 Resources Corp. (the “Company”) on Form 10-K for the year
ended December 31, 2008 (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.
|
/s/
Gary L. Whitlock
|
|
|
Gary
L. Whitlock
|
|
|
Executive
Vice President and Chief Financial Officer
|
|
|
March 11,
2009
|