UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
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(Mark
One)
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R
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QUARTERLY REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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FOR
THE QUARTERLY PERIOD ENDED MARCH 31, 2009
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OR
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£
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
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FOR
THE TRANSITION PERIOD FROM
TO
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Commission
file number 1-13265
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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CenterPoint
Energy Resources Corp. meets the conditions set forth in General Instruction
H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the
reduced disclosure format.
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 whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes £ No £
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
definitions of “large accelerated filer”, “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):
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Large accelerated filer o
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Accelerated
filer o
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Non-accelerated
filer þ
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Smaller
reporting company o
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(Do
not check if a smaller reporting company)
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes £ No R
As of
April 30, 2009, all 1,000 shares of CenterPoint Energy Resources Corp. common
stock were held by Utility Holding, LLC, a wholly owned subsidiary of
CenterPoint Energy, Inc.
CENTERPOINT
ENERGY RESOURCES CORP.
QUARTERLY
REPORT ON FORM 10-Q
FOR
THE QUARTER ENDED MARCH 31, 2009
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PART
I.
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FINANCIAL
INFORMATION
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Item
1.
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1
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Three
Months Ended March 31, 2008 and 2009 (unaudited)
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1
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December 31,
2008 and March 31, 2009 (unaudited)
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2
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Three
Months Ended March 31, 2008 and 2009 (unaudited)
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4
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5
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Item
2.
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19
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Item
4T.
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27
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PART
II.
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OTHER
INFORMATION
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Item
1.
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27
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Item
1A.
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27
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Item
5.
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27
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Item
6.
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28
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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.
The
following are some of the factors that could cause actual results to differ
materially from those expressed or implied in forward-looking
statements:
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•
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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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•
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timely
and appropriate rate actions and increases, allowing recovery of costs and
a reasonable return on investment;
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•
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cost
overruns on major capital projects that cannot be recouped in
prices;
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•
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industrial,
commercial and residential growth in our service territory and changes in
market demand and demographic
patterns;
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•
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the
timing and extent of changes in commodity prices, particularly natural gas
and natural gas liquids;
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•
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the
timing and extent of changes in the supply of natural
gas;
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•
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the
timing and extent of changes in natural gas basis
differentials;
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•
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weather
variations and other natural
phenomena;
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•
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changes
in interest rates or rates of
inflation;
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•
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commercial
bank and financial market conditions, our access to capital, the cost of
such capital, and the results of our financing and refinancing efforts,
including availability of funds in the debt capital
markets;
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•
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actions
by rating agencies;
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•
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effectiveness
of our risk management activities;
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•
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inability
of various counterparties to meet their obligations to
us;
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•
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non-payment
for our services due to financial distress of our
customers;
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•
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the
ability of Reliant Energy, Inc., now known as RRI Energy, Inc., and its
subsidiaries and any successors to satisfy their other obligations to us,
including indemnity obligations, or in connection with the contractual
arrangements pursuant to which we are their
guarantor;
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•
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the
outcome of litigation brought by or against
us;
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•
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our
ability to control costs;
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the
investment performance of CenterPoint Energy, Inc.’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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acquisition
and merger activities involving our parent or our competitors;
and
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•
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other
factors we discuss in “Risk Factors” in Item 1A of Part I of our Annual
Report on Form 10-K for the year ended December 31, 2008, which is
incorporated herein by reference, and other reports we file from time to
time with the Securities and Exchange
Commission.
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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. FINANCIAL INFORMATION
(AN
INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED
STATEMENTS OF CONSOLIDATED INCOME
(Millions
of Dollars)
(Unaudited)
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Three
Months Ended March 31,
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||||||||
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2008
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2009
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Revenues
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$ | 2,952 | $ | 2,351 | ||||
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Expenses:
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Natural
gas
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2,393 | 1,789 | ||||||
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Operation
and maintenance
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205 | 233 | ||||||
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Depreciation
and amortization
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54 | 57 | ||||||
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Taxes
other than income taxes
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58 | 58 | ||||||
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Total
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2,710 | 2,137 | ||||||
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Operating
Income
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242 | 214 | ||||||
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Other
Income (Expense):
Interest
and other finance charges
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(48 | ) | (54 | ) | ||||
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Equity
in earnings of unconsolidated affiliates
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9 | — | ||||||
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Other,
net
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2 | 1 | ||||||
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Total
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(37 | ) | (53 | ) | ||||
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Income
Before Income Taxes
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205 | 161 | ||||||
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Income
tax expense
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(79 | ) | (66 | ) | ||||
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Net
Income
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$ | 126 | $ | 95 | ||||
See Notes
to the Company’s Interim Condensed Consolidated Financial
Statements
(AN
INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED
CONSOLIDATED BALANCE SHEETS
(Millions
of Dollars)
(Unaudited)
ASSETS
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December 31,
2008
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March 31,
2009
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Current
Assets:
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Cash
and cash equivalents
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$ | 1 | $ | 6 | ||||
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Accounts
and notes receivable, net
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774 | 682 | ||||||
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Accrued
unbilled revenue
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480 | 247 | ||||||
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Accounts
and notes receivable – affiliated companies
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9 | 9 | ||||||
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Materials
and supplies
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54 | 64 | ||||||
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Natural
gas inventory
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441 | 12 | ||||||
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Non-trading
derivative assets
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118 | 119 | ||||||
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Deferred
tax asset
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25 | 8 | ||||||
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Prepaid
expenses and other current assets
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327 | 287 | ||||||
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Total
current assets
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2,229 | 1,434 | ||||||
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Property,
Plant and Equipment:
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Property,
plant and equipment
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6,313 | 6,437 | ||||||
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Less
accumulated depreciation and amortization
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950 | 1,002 | ||||||
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Property,
plant and equipment, net
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5,363 | 5,435 | ||||||
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Other
Assets:
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Goodwill
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1,696 | 1,696 | ||||||
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Non-trading
derivative assets
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20 | 23 | ||||||
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Investment
in unconsolidated affiliates
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345 | 343 | ||||||
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Notes
receivable from unconsolidated affiliates
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323 | 323 | ||||||
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Other
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235 | 259 | ||||||
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Total
other assets
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2,619 | 2,644 | ||||||
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Total
Assets
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$ | 10,211 | $ | 9,513 | ||||
See Notes
to the Company’s Interim Condensed Consolidated Financial
Statements
CENTERPOINT
ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN
INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED
CONSOLIDATED BALANCE SHEETS — (Continued)
(Millions
of Dollars)
(Unaudited)
LIABILITIES
AND STOCKHOLDER’S EQUITY
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December 31,
2008
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March 31,
2009
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Current
Liabilities:
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Short-term
borrowings
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$ | 153 | $ | 215 | ||||
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Current
portion of long-term debt
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7 | 7 | ||||||
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Accounts
payable
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722 | 369 | ||||||
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Accounts
and notes payable — affiliated companies
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33 | 32 | ||||||
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Taxes
accrued
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99 | 102 | ||||||
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Interest
accrued
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54 | 68 | ||||||
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Customer
deposits
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59 | 62 | ||||||
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Non-trading
derivative liabilities
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87 | 63 | ||||||
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Other
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302 | 166 | ||||||
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Total
current liabilities
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1,516 | 1,084 | ||||||
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Other
Liabilities:
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Accumulated
deferred income taxes, net
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864 | 888 | ||||||
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Non-trading
derivative liabilities
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47 | 47 | ||||||
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Benefit
obligations
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114 | 112 | ||||||
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Regulatory
liabilities
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508 | 521 | ||||||
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Other
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101 | 117 | ||||||
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Total
other liabilities
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1,634 | 1,685 | ||||||
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Long-term
Debt
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3,712 | 3,300 | ||||||
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Commitments
and Contingencies (Note 11)
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Stockholder’s
Equity:
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Common
stock
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— | — | ||||||
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Paid-in
capital
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2,416 | 2,416 | ||||||
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Retained
earnings
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935 | 1,030 | ||||||
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Accumulated
other comprehensive loss
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(2 | ) | (2 | ) | ||||
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Total
stockholder’s equity
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3,349 | 3,444 | ||||||
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Total
Liabilities and Stockholder’s Equity
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$ | 10,211 | $ | 9,513 | ||||
See Notes
to the Company’s Interim Condensed Consolidated Financial
Statements
(AN
INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions
of Dollars)
(Unaudited)
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Three
Months Ended March 31,
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2008
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2009
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Cash
Flows from Operating Activities:
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Net
income
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$ | 126 | $ | 95 | ||||
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Adjustments
to reconcile net income to net cash provided by operating
activities:
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Depreciation
and amortization
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54 | 57 | ||||||
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Amortization
of deferred financing costs
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2 | 2 | ||||||
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Deferred
income taxes
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28 | 41 | ||||||
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Write-down
of natural gas inventory
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— | 6 | ||||||
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Equity
in earnings of unconsolidated affiliates, net of
distributions
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(9 | ) | — | |||||
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Changes
in other assets and liabilities:
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||||||||
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Accounts
receivable and unbilled revenues, net
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(103 | ) | 273 | |||||
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Accounts
receivable/payable, affiliates
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51 | (1 | ) | |||||
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Inventory
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328 | 413 | ||||||
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Accounts
payable
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46 | (341 | ) | |||||
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Fuel
cost over (under) recovery
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29 | (30 | ) | |||||
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Interest
and taxes accrued
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4 | 17 | ||||||
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Non-trading
derivatives, net
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27 | 11 | ||||||
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Margin
deposits, net
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29 | (62 | ) | |||||
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Other
current assets
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57 | 54 | ||||||
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Other
current liabilities
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(64 | ) | (51 | ) | ||||
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Other
assets
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4 | 1 | ||||||
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Other
liabilities
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(55 | ) | — | |||||
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Net
cash provided by operating activities
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554 | 485 | ||||||
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Cash
Flows from Investing Activities:
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Capital
expenditures
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(94 | ) | (132 | ) | ||||
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Increase
in notes receivable from affiliates, net
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(2 | ) | — | |||||
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Investment
in unconsolidated affiliates
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(105 | ) | 2 | |||||
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Net
cash used in investing activities
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(201 | ) | (130 | ) | ||||
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Cash
Flows from Financing Activities:
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Increase
(decrease) in short-term borrowings
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(32 | ) | 62 | |||||
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Long-term
revolving credit facility, net
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(50 | ) | (425 | ) | ||||
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Proceeds
from commercial paper, net
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35 | 19 | ||||||
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Payments
of long-term debt
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(307 | ) | (6 | ) | ||||
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Increase
in notes payable with affiliates
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19 | — | ||||||
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Net
cash used in financing activities
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(335 | ) | (350 | ) | ||||
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Net
Increase in Cash and Cash Equivalents
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18 | 5 | ||||||
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Cash
and Cash Equivalents at Beginning of the Period
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1 | 1 | ||||||
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Cash
and Cash Equivalents at End of the Period
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$ | 19 | $ | 6 | ||||
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Supplemental
Disclosure of Cash Flow Information:
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Cash
Payments:
|
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Interest,
net of capitalized interest
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$ | 46 | $ | 37 | ||||
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Income
taxes
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36 | 19 | ||||||
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Non-cash
transactions:
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Accounts
payable related to capital expenditures
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44 | 39 | ||||||
See Notes
to the Company’s Interim Condensed Consolidated Financial
Statements
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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(1)
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Background
and Basis of Presentation
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General. Included
in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy
Resources Corp. (CERC Corp.) are the condensed consolidated interim financial
statements and notes (Interim Condensed Financial Statements) of CenterPoint
Energy Resources Corp. and its subsidiaries (collectively, CERC or the
Company). The Interim Condensed Financial Statements are unaudited,
omit certain financial statement disclosures and should be read with the Annual
Report on Form 10-K of CERC Corp. for the year ended December 31, 2008
(CERC Corp. Form 10-K).
Background. 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.
The
Company is an indirect wholly owned subsidiary of CenterPoint Energy, Inc.
(CenterPoint Energy), a public utility holding company.
Basis of Presentation. 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.
The
Company’s Interim Condensed Financial Statements reflect all normal recurring
adjustments that are, in the opinion of management, necessary to present fairly
the financial position, results of operations and cash flows for the respective
periods. Amounts reported in the Company’s Condensed Statements of
Consolidated Income are not necessarily indicative of amounts expected for a
full-year period due to the effects of, among other things, (a) seasonal
fluctuations in demand for energy and energy services, (b) changes in energy
commodity prices, (c) timing of maintenance and other expenditures and (d)
acquisitions and dispositions of businesses, assets and other
interests.
For a
description of the Company’s reportable business segments, see Note
13.
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(2)
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New
Accounting Pronouncements
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In
December 2007, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standard (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’s adoption of SFAS No. 160 as of January 1, 2009 did not have a material
impact on its financial position, results of operations or cash
flows.
Effective
January 1, 2009, the Company adopted 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) which requires
5
enhanced
disclosures of derivative instruments and hedging activities such as the fair
value of derivative instruments and presentation of their gains or losses in
tabular format, as well as disclosures regarding credit risks and strategies and
objectives for using derivative instruments. These disclosures are
included as part of the Company’s Derivatives Instruments footnote (see Note
5).
In
December 2008, the FASB issued FASB Staff Position No. FAS 132(R)-1, “Employers’
Disclosures about Postretirement Benefit Plan Assets” (FSP 132(R)-1), which
amends SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other
Postretirement Benefits.” FSP 132(R)-1 expands the disclosures about
employers’ plan assets to include more detailed disclosures about the employers’
investment strategies, major categories of plan assets, concentrations of risk
within plan assets and valuation techniques used to measure the fair value of
plan assets. FSP 132(R)-1 is effective for fiscal years ending after December
15, 2009. The Company expects that the adoption of FSP 132(R)-1 will not have a
material impact on its financial position, results of operations or cash
flows.
In April
2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1, “Interim
Disclosures about Fair Value of Financial Instruments” (FSP 107-1), which amends
SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” (SFAS No.
107) and APB 28-1, “Interim Financial Reporting.” FSP 107-1 expands the fair
value disclosures required for all financial instruments within the scope of
SFAS No. 107 to interim periods. FSP 107-1 also requires entities to disclose in
interim periods the methods and significant assumptions used to estimate the
fair value of financial instruments. FSP 107-1 is effective for interim
reporting periods ending after June 15, 2009. The Company expects that the
adoption of FSP 107-1 will not have a material impact on its financial position,
results of operations or cash flows.
|
(3)
|
Employee
Benefit Plans
|
The
Company’s employees participate in CenterPoint Energy’s postretirement benefit
plan. The Company’s net periodic cost relating to postretirement
benefits includes $2 million of interest cost for each of the three months
ended March 31, 2008 and 2009. The Company expects to contribute
approximately $15 million to CenterPoint Energy’s postretirement benefits
plan in 2009, of which $4 million had been contributed as of March 31,
2009.
|
(4)
|
Regulatory
Matters
|
Texas. In March 2008, the
Company’s natural gas distribution businesses (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. In December 2008, Gas Operations implemented the approved
rates for the nine TCUC cities and the environs. In February 2009,
the Railroad Commission denied the second motions on rehearing reaffirming its
original decision. Cities with settled rates have the opportunity to
adopt the rates established by the Railroad Commission or retain the rates
agreed to in their settlements. In March 2009, TCUC and the State of
Texas appealed the Railroad Commission’s decision to the 353rd
Judicial District Court, Travis County, Texas. 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.
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
6
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 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 Company does
not expect an order from the MPUC until early 2010.
|
(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. Such contracts are recognized in the
Company’s Condensed 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, the effective portions of the
changes in their fair values are reflected initially as a separate component of
stockholders’ 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 the Company’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.
(a) Non-Trading
Activities
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 three months ended
March 31, 2008, the Company
7
decreased
natural gas revenues from unrealized net losses of $20 million and
increased natural gas expense from unrealized net losses of $2 million,
resulting in a net unrealized loss of $22 million. During the three months
ended March 31, 2009, the Company increased revenues from unrealized net
gains of $3 million and increased natural gas expense from unrealized net
losses of $22 million, resulting in a net unrealized loss of
$19 million.
In prior
years, the Company entered into certain derivative instruments that were
designated as cash flow hedges under SFAS No. 133. The objective of
these derivative instruments was to hedge the price risk associated with natural
gas purchases and sales to reduce cash flow variability related to meeting the
Company’s wholesale and retail customer obligations. In 2007, the Company
discontinued designating these instruments as cash flow hedges under SFAS No.
133. As of March 31, 2009, there are no remaining amounts deferred in
other comprehensive income related to these instruments that had previously been
designated as cash flow hedges.
Weather
Derivatives. The Company has weather normalization or other
rate mechanisms that mitigate the impact of weather on its operations 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. 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 three months ended
March 31, 2008 and 2009, the Company recognized losses of $11 million
and $3 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
Condensed Statements of Consolidated Income.
(b)
Derivative Fair Values and Income Statement Impacts
The
following tables present information about the Company’s derivative instruments
and hedging activities. The first table provides a balance sheet
overview of the Company’s Derivative Assets and Liabilities as of March 31,
2009, while the latter table provides a breakdown of the related income
statement impact for the three months ended March 31, 2009.
|
Fair
Value of Derivative Instruments
|
||||||||||
|
March
31, 2009
|
||||||||||
|
Total
derivatives not designated as hedging
instruments
under SFAS 133
|
Balance
Sheet
Location
|
Derivative
Assets
Fair
Value (2) (3)
|
Derivative
Liabilities
Fair
Value (2) (3)
|
|||||||
|
(in
millions)
|
||||||||||
|
Commodity
contracts (1)
|
Current
Assets
|
$ | 133 | $ | (14 | ) | ||||
|
Commodity
contracts (1)
|
Other
Assets
|
24 | (1 | ) | ||||||
|
Commodity
contracts (1)
|
Current
Liabilities
|
12 | (222 | ) | ||||||
|
Commodity
contracts (1)
|
Other
Liabilities
|
1 | (149 | ) | ||||||
|
Total
|
$ | 170 | $ | (386 | ) | |||||
|
(1)
|
Commodity
contracts are subject to master netting arrangements and are presented on
a net basis in the Consolidated Balance Sheet. This netting causes
derivative assets (liabilities) to be ultimately presented net in a
liability (asset) account within the Consolidated Balance
Sheet.
|
|
(2)
|
The
fair value shown for commodity contracts is comprised of derivative
volumes totaling 688 billion cubic feet (Bcf). These
volumes are disclosed in absolute terms, not net. Basis swaps
constitute 261 Bcf of the
total.
|
|
(3)
|
The
net of total non-trading derivative assets and liabilities is $32 million
as shown on the Company’s Condensed Consolidated Balance Sheets, and is
comprised of the commodity contracts derivative assets and liabilities
separately shown above offset by collateral netting of $248
million.
|
For the
Company’s price stabilization activities of the Natural Gas Distribution
business segment, the settled costs of derivatives are ultimately recovered
through purchased gas adjustments. Accordingly, the net unrealized gains and
losses associated with interim price movements on contracts that are accounted
for as derivatives and probable of recovery through purchased gas adjustments
are recorded as net regulatory assets. For those derivatives that are not
included in purchased gas adjustments, unrealized gains and losses and settled
amounts are recognized on the Condensed Statements of Consolidated Income as
revenue for retail sales derivative contracts and as natural gas expense for
natural gas derivatives and non-retail related physical gas
derivatives.
|
Income
Statement Impact of Derivative Activity
|
||||||
|
Total
derivatives not designated as hedging
instruments
under SFAS 133
|
Income
Statement Location
|
Three
Months Ended
March
31, 2009
|
||||
|
(in
millions)
|
||||||
|
Commodity
contracts
|
Gains
(Losses) in Revenue
|
$ | 77 | |||
|
Commodity
contracts (1)
|
Gains
(Losses) in Expense: Natural Gas
|
(149 | ) | |||
|
Total
|
$ | (72 | ) | |||
|
(1)
|
The Gains (Losses) in Expense:
Natural Gas contains $(78) million of costs associated with price
stabilization activities of our Natural Gas Distribution business segment
which are ultimately recovered through purchased gas
adjustments. In addition, for the period a $(91) million
unrealized loss associated with unsettled price stabilization derivatives
was recorded into the net regulatory asset
account.
|
(c)
Credit Risk Contingent Features
The
Company enters into financial derivative contracts containing material adverse
change provisions. These provisions require the Company to post
additional collateral if the Standard & Poor’s Rating Services or Moody’s
Investors Service, Inc. credit rating of the Company is
downgraded. The total fair value of the derivative instruments that
contain credit risk contingent features that are in a net liability position at
March 31, 2009 is $250 million. The aggregate fair value of assets
that are already posted as collateral at March 31, 2009 is $162
million. If all derivative contracts (in a net liability position)
containing credit risk contingent features were triggered at March 31, 2009, $88
million of additional assets would be required to be posted as
collateral.
|
(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. Effective January 1, 2009, the Company adopted SFAS No. 157 for
nonfinancial assets and liabilities, which adoption had no impact on the
Company’s financial position, results of operations or cash
flows. 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. Unobservable inputs reflect the Company’s
judgments
about the
assumptions market participants would use in pricing the asset or liability
since limited market data exists. The Company develops these inputs based on the
best information available, including the Company’s own data. The
Company’s Level 3 derivative instruments primarily consist of options that are
not traded on recognized exchanges and are valued using option pricing
models.
The
following 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 March 31, 2009, 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
March
31,
2009
|
||||||||||||||||
|
(in
millions)
|
||||||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Investments,
including money
market
funds
|
$ | 11 | $ | — | $ | — | $ | — | $ | 11 | ||||||||||
|
Derivative
assets
|
1 | 164 | 7 | (30 | ) | 142 | ||||||||||||||
|
Total
assets
|
$ | 12 | $ | 164 | $ | 7 | $ | (30 | ) | $ | 153 | |||||||||
|
Liabilities
|
||||||||||||||||||||
|
Derivative
liabilities
|
41 | 314 | 33 | (278 | ) | 110 | ||||||||||||||
|
Total
liabilities
|
$ | 41 | $ | 314 | $ | 33 | $ | (278 | ) | $ | 110 | |||||||||
__________
|
(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 of $248 million posted 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
three months ended March 31, 2009:
|
Fair
Value Measurements
Using
Significant
Unobservable
Inputs
(Level
3)
|
||||
|
Derivative
assets and
liabilities,
net
|
||||
|
(in
millions)
|
||||
|
Beginning
liability balance as of January 1, 2009
|
$ | (58 | ) | |
|
Total
gains or (losses) (unrealized and realized):
|
||||
|
Included
in earnings
|
(3 | ) | ||
|
Included
in regulatory assets
|
(17 | ) | ||
|
Purchases,
sales, other settlements, net (1)
|
52 | |||
|
Ending
liability balance as of March 31, 2009
|
$ | (26 | ) | |
|
The
amount of total losses for the period included in earnings attributable to
the
change
in unrealized gains or losses relating to assets still held at the
reporting
date
|
$ | (2 | ) | |
|
(1)
|
Purchases,
sales, other settlements, net includes $50 million associated with price
stabilization activities of the Company’s Natural Gas Distribution
business segment.
|
|
(7)
|
Goodwill
|
Goodwill
by reportable business segment as of both December 31, 2008 and
March 31, 2009 is as follows (in millions):
|
Natural
Gas Distribution
|
$ | 746 | ||
|
Interstate
Pipelines
|
579 | |||
|
Competitive
Natural Gas Sales and Services
|
335 | |||
|
Field
Services
|
25 | |||
|
Other
Operations
|
11 | |||
|
Total
|
$ | 1,696 |
|
(8)
|
Comprehensive
Income
|
The
following table summarizes the components of total comprehensive income (net of
tax):
|
For
the Three Months Ended
March 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
(in
millions)
|
||||||||
|
Net
income
|
$ | 126 | $ | 95 | ||||
|
Other
comprehensive income (loss):
|
||||||||
|
Reclassification
of deferred gain from cash flow hedges realized in net income
(net
of tax of $2)
|
(4
|
) | — | |||||
|
Other
comprehensive loss
|
(4 | ) | — | |||||
|
Comprehensive
income
|
$ | 122 | $ | 95 | ||||
The
following table summarizes the components of accumulated other comprehensive
loss:
|
December 31,
2008
|
March 31,
2009
|
|||||||
|
(in
millions)
|
||||||||
|
Adjustment
to pension and other postretirement plans
|
$ | (2 | ) | $ | (2 | ) | ||
|
Total
accumulated other comprehensive loss
|
$ | (2 | ) | $ | (2 | ) | ||
|
(9)
|
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 by CenterPoint Energy under
its revolving credit facility or the sale by CenterPoint Energy of its
commercial paper. As of December 31, 2008 and March 31, 2009, the
Company had no borrowings from the money pool.
For the
three months ended March 31, 2008 and 2009, the Company had net interest
expense related to affiliate borrowings of approximately $1 million and
$-0-, 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 $35 million and $37 million for the three
months ended March 31, 2008 and 2009, respectively, and are included
primarily in operation and maintenance expenses.
|
(10)
|
Short-term
Borrowings and 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, 2008 and March 31, 2009 the
facility size was $128 million and $375 million, respectively. As of
December 31, 2008 and March 31, 2009, advances under the receivables
facility were $78 million and $215 million, respectively.
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 and March 31, 2009,
the Company’s financial statements reflect natural gas inventory of
$75 million and $-0-, respectively, and a financing obligation of
$75 million and $-0-, respectively, related to this
transaction.
(b)
Long-term Debt
Revolving Credit
Facility. The Company’s $950 million 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 a
debt to total capitalization covenant. Under the Company’s
$950 million credit facility, an additional utilization fee of 5 basis
points applies to borrowings any time more than 50% of the facility is utilized.
The spread to LIBOR and the utilization fee fluctuate based on the Company’s
credit rating.
As of
December 31, 2008 and March 31, 2009, the Company had $926 million and
$501 million, respectively, of borrowings under its $950 million credit
facility. There was $-0- and $19 million of commercial paper
outstanding that was backstopped by the Company’s $950 million credit
facility at December 31, 2008 and March 31, 2009, respectively. The Company was
in compliance with all debt covenants as of March 31, 2009.
|
(11)
|
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, 2008 and March 31, 2009
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 March 31, 2009, minimum payment
obligations for natural gas supply commitments are approximately
$333 million for the remaining nine months in 2009, $460 million in
2010, $396 million in 2011, $393 million in 2012, $381 million in
2013 and $930 million after 2013.
(b)
Legal, Environmental and Other Regulatory Matters
Legal
Matters
RRI
Indemnified Litigation
Gas Market Manipulation
Cases. CenterPoint Energy or its predecessor, Reliant Energy,
Incorporated (Reliant Energy), and certain of their present and former
subsidiaries are named as defendants in several lawsuits described below. Under
a master separation agreement between CenterPoint Energy and Reliant Energy,
Inc., now known as RRI Energy, Inc. (RRI), CenterPoint Energy and its
subsidiaries are entitled to be indemnified by RRI for any losses, including
attorneys’ fees and other costs, arising out of these
lawsuits. Pursuant to the indemnification obligation, RRI is
defending CenterPoint Energy and its subsidiaries to the extent named in these
lawsuits. A large number of lawsuits were filed against numerous gas
market participants in a number of federal and western state courts in
connection with the operation of the natural gas markets in 2000-2002.
CenterPoint Energy’s former
12
affiliate,
RRI, was a participant in gas trading in the California and Western markets.
These lawsuits, many of which have been filed as class actions, allege
violations of state and federal antitrust laws. Plaintiffs in these lawsuits are
seeking a variety of forms of relief, including, among others, recovery of
compensatory damages (in some cases in excess of $1 billion), a trebling of
compensatory damages, full consideration damages and attorneys’ fees.
CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these
lawsuits, which were instituted between 2003 and 2009. Most of these cases have
settled or CenterPoint Energy has been dismissed from them. CenterPoint Energy
Services, Inc. (CES), a subsidiary of CERC Corp., is a defendant or sought to be
added as a defendant in two cases now pending in federal court in Wisconsin and
Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in
2000-2002. Additionally, CenterPoint Energy was a defendant in a
lawsuit filed in state court in Nevada that was dismissed in 2007, but the
plaintiffs have asked for reconsideration of the dismissal. CenterPoint Energy
believes that neither it nor CES is a proper defendant in the remaining cases
and will continue to pursue dismissal from those cases. The Company
does not expect the ultimate outcome of these matters to have a material impact
on its financial condition, results of operations or cash
flows.
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 sought review of that dismissal from the Tenth Circuit
Court of Appeals, which affirmed the district court’s dismissal in March 2009.
The plaintiff has indicated that he intends to seek rehearing of the Tenth
Circuit decision.
In
addition, CERC Corp. and certain of its subsidiaries are defendants in two
mismeasurement lawsuits brought against approximately 245 pipeline companies and
their affiliates pending in state court in Stevens County, Kansas. In
one case (originally filed in May 1999 and amended four times), the plaintiffs
purport to represent a class of royalty owners who allege that the defendants
have engaged in systematic mismeasurement of the volume of natural gas for more
than 25 years. The plaintiffs amended their petition in this suit in July 2003
in response to an order from the judge denying certification of the plaintiffs’
alleged class. In the amendment the plaintiffs dismissed their claims against
certain defendants (including two CERC Corp. subsidiaries), limited the scope of
the class of plaintiffs they purport to represent and eliminated previously
asserted claims based on mismeasurement of the British thermal unit (Btu)
content of the gas. The same plaintiffs then filed a second lawsuit, again as
representatives of a putative class of royalty owners, in which they assert
their claims that the defendants have engaged in systematic mismeasurement of
the Btu content of natural gas for more than 25 years. In both lawsuits, the
plaintiffs seek compensatory damages, along with statutory penalties, treble
damages, interest, costs and fees.
The
Company believes that there has been no systematic mismeasurement of gas and
that these 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.
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, CenterPoint Energy Gas Transmission Company (CEGT),
CenterPoint Energy Field Services (CEFS), CEPS, Mississippi River
Transmission
13
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. The
Company does not expect the outcome of this proceeding to have a material
adverse impact on its financial condition, results of operations or cash
flows.
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 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
14
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 March
31, 2009, 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 March 31, 2009, 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 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 its 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
15
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 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 March 31, 2009. RRI
continues to meet its obligations under the contracts, and, on the basis of
current market conditions, the Company and CenterPoint Energy believe that
additional security is not needed at this time. 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.
|
(12)
|
Income
Taxes
|
During
the three months ended March 31, 2008 and 2009, the effective tax rate was 38%
and 41%, respectively. The most significant item affecting the comparability of
the effective tax rate is a $4 million increase in the 2009 income tax expense
as a result of a state tax audit.
The
following table summarizes the Company’s liability (receivable) for uncertain
tax positions in accordance with FASB Interpretation No. (FIN) 48, “Accounting
for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109”
at December 31, 2008 and March 31, 2009:
|
December 31,
2008
|
March 31,
2009
|
|||||||
|
(in
millions)
|
||||||||
|
Receivable
for uncertain tax positions
|
$ | (12 | ) | $ | (12 | ) | ||
|
Portion
of receivable for uncertain tax positions that, if
recognized,
would reduce the effective income tax rate
|
1 | 1 | ||||||
|
Interest
accrued on uncertain tax positions
|
(4 | ) | (4 | ) | ||||
|
(13)
|
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
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
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.
Financial
data for business segments and products and services are as follows (in
millions):
|
For
the Three Months Ended March 31, 2008
|
||||||||||||||||
|
Revenues
from External Customers
|
Net
Intersegment Revenues
|
Operating
Income (Loss)
|
Total
Assets
as
of December 31,
2008
|
|||||||||||||
|
Natural
Gas Distribution
|
$ | 1,697 | $ | 3 | $ | 121 | $ | 4,961 | ||||||||
|
Competitive
Natural Gas Sales and Services
|
1,109 | 11 | 6 | 1,315 | ||||||||||||
|
Interstate
Pipelines
|
91 | 42 | 71 | 3,578 | ||||||||||||
|
Field
Services
|
54 | 4 | 45 | 826 | ||||||||||||
|
Other
Operations
|
1 | — | (1 | ) | 724 | |||||||||||
|
Eliminations
|
— | (60 | ) | — | (1,193 | ) | ||||||||||
|
Consolidated
|
$ | 2,952 | $ | — | $ | 242 | $ | 10,211 | ||||||||
|
For
the Three Months Ended March 31, 2009
|
||||||||||||||||
|
Revenues
from External Customers
|
Net
Intersegment Revenues
|
Operating
Income (Loss)
|
Total
Assets
as
of March 31,
2009
|
|||||||||||||
|
Natural
Gas Distribution
|
$ | 1,418 | $ | 3 | $ | 118 | $ | 4,344 | ||||||||
|
Competitive
Natural Gas Sales and Services
|
760 | 5 | 2 | 1,169 | ||||||||||||
|
Interstate
Pipelines
|
117 | 36 | 69 | 3,579 | ||||||||||||
|
Field
Services
|
56 | 1 | 26 | 829 | ||||||||||||
|
Other
Operations
|
— | — | (1 | ) | 615 | |||||||||||
|
Eliminations
|
— | (45 | ) | — | (1,023 | ) | ||||||||||
|
Consolidated
|
$ | 2,351 | $ | — | $ | 214 | $ | 9,513 | ||||||||
|
(14)
|
Subsequent
Events
|
On May 1,
2009, RRI completed the previously announced sale of its Texas retail business
to NRG Retail LLC, a subsidiary of NRG Energy, Inc.
In
connection with the sale, RRI changed its name to RRI Energy, Inc. The sale does
not alter RRI’s contractual obligations to indemnify CenterPoint Energy and its
subsidiaries, including the Company, for certain liabilities, including their
indemnification regarding certain litigation, nor does it affect the terms of
existing guaranty arrangements for certain RRI gas transportation
contracts.
Item 2. MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
The
following narrative analysis should be read in combination with our Interim
Condensed Financial Statements contained in Item 1 of this report and our Annual
Report on Form 10-K for the year ended December 31, 2008 (2008 Form
10-K).
We meet
the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and
are therefore permitted to use the reduced disclosure format for wholly owned
subsidiaries of reporting companies. Accordingly, we have omitted
from this report the information called for by Item 2 (Management’s Discussion
and Analysis of Financial Condition and Results of Operations) and Item 3
(Quantitative and Qualitative Disclosures About Market Risk) of Part I and the
following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity
Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and
Item 4 (Submission of Matters to a Vote of Security Holders). The
following discussion explains material changes in our revenue and expense items
between the three months ended March 31, 2008 and the three months ended
March 31, 2009. Reference is made to “Management’s Narrative
Analysis of Results of Operations” in Item 7 of our 2008 Form 10-K.
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, state and local governmental
authorities having jurisdiction over rates we charge, competition in our various
business operations, debt service costs and income tax expense. For
more information regarding factors that may affect the future results of
operations of our business, please read “Risk Factors” in Item 1A of Part I of
our 2008 Form 10-K.
The
following table sets forth our consolidated results of operations for the three
months ended March 31, 2008 and 2009, followed by a discussion of our
consolidated results of operations.
|
Three
Months Ended March 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
(in
millions)
|
||||||||
|
Revenues
|
$ | 2,952 | $ | 2,351 | ||||
|
Expenses:
|
||||||||
|
Natural
gas
|
2,393 | 1,789 | ||||||
|
Operation
and maintenance
|
205 | 233 | ||||||
|
Depreciation
and amortization
|
54 | 57 | ||||||
|
Taxes
other than income taxes
|
58 | 58 | ||||||
|
Total
expenses
|
2,710 | 2,137 | ||||||
|
Operating
Income
|
242 | 214 | ||||||
|
Interest
and other finance charges
|
(48 | ) | (54 | ) | ||||
|
Equity
in earnings of unconsolidated affiliates
|
9 | — | ||||||
|
Other
income, net
|
2 | 1 | ||||||
|
Income
Before Income Taxes
|
205 | 161 | ||||||
|
Income
tax expense
|
(79 | ) | (66 | ) | ||||
|
Net
Income
|
$ | 126 | $ | 95 | ||||
Three
months ended March 31, 2009 compared to three months ended March 31,
2008
We
reported net income of $95 million for the three months ended March 31,
2009 as compared to $126 million for the same period in
2008. The decrease in net income of $31 million was primarily
due to a $28 million decrease in operating income from our business
segments as discussed below, a $9 million decrease in equity in earnings of
unconsolidated affiliates and a $6 million increase in interest and other
finance charges, partially offset by a $13 million decrease in income tax
expense.
Income Tax Expense. During the three months
ended March 31, 2008 and 2009, the effective tax rate was 38% and 41%,
respectively. The most significant item affecting the comparability of the
effective tax rate is a $4 million increase in the 2009 income tax expense as a
result of a state tax audit.
RESULTS
OF OPERATIONS BY BUSINESS SEGMENT
The
following table presents operating income (loss) for each of our business
segments for the three months ended March 31, 2008 and 2009, followed by a
discussion of the results of operations by business segment based on operating
income. 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.
|
Three
Months Ended March 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
(in
millions)
|
||||||||
|
Natural
Gas Distribution
|
$ | 121 | $ | 118 | ||||
|
Competitive
Natural Gas Sales and Services
|
6 | 2 | ||||||
|
Interstate
Pipelines
|
71 | 69 | ||||||
|
Field
Services
|
45 | 26 | ||||||
|
Other
Operations
|
(1 | ) | (1 | ) | ||||
|
Total
Consolidated Operating Income
|
$ | 242 | $ | 214 | ||||
Natural
Gas Distribution
For
information regarding factors that may affect the future results of operations
of our Natural Gas Distribution business segment, please read “Risk Factors
— Risk
Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales
and Services, Interstate Pipelines and Field Services Businesses,” “ — Risk Factors
Associated with Our Consolidated Financial Condition” and “— Risks Common to Our
Business and Other Risks” in Item 1A of Part I of our 2008 Form
10-K.
The
following table provides summary data of our Natural Gas Distribution business
segment for the three months ended March 31, 2008 and 2009 (in millions,
except throughput and customer data):
|
Three
Months Ended March 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
Revenues
|
$ | 1,700 | $ | 1,421 | ||||
|
Expenses:
|
||||||||
|
Natural
gas
|
1,333 | 1,045 | ||||||
|
Operation
and maintenance
|
156 | 169 | ||||||
|
Depreciation
and amortization
|
39 | 40 | ||||||
|
Taxes
other than income taxes
|
51 | 49 | ||||||
|
Total
expenses
|
1,579 | 1,303 | ||||||
|
Operating
Income
|
$ | 121 | $ | 118 | ||||
|
Throughput
(in billion cubic feet (Bcf)):
|
||||||||
|
Residential
|
84 | 78 | ||||||
|
Commercial
and industrial
|
83 | 73 | ||||||
|
Total
Throughput
|
167 | 151 | ||||||
|
Number
of customers at period end:
|
||||||||
|
Residential
|
2,974,411 | 2,996,455 | ||||||
|
Commercial
and industrial
|
251,612 | 246,405 | ||||||
|
Total
|
3,226,023 | 3,242,860 | ||||||
Three
months ended March 31, 2009 compared to three months ended March 31,
2008
Our
Natural Gas Distribution business segment reported operating income of
$118 million for the three months ended March 31, 2009 compared to
operating income of $121 million for the three months ended March 31,
2008. Operating margin (revenues less cost of gas) increased
$9 million primarily due to increased rates ($10 million), recovery of
energy-efficiency costs ($3 million) and higher miscellaneous revenue
($3 million), partially offset by reduced customer usage ($6 million)
and decreased gross receipts taxes ($3 million). Margin increases from
residential customer growth ($1 million), with the addition of
approximately 22,000 residential customers, were
20
offset by
reduced margin caused by the loss of commercial customers. Revenues
related to both energy-efficiency costs and gross receipts taxes were offset by
the related expenses. Operation and maintenance expenses increased
$13 million primarily due to increased pension expense ($9 million),
the energy-efficiency costs above and higher bad debt expense
($2 million).
Competitive
Natural Gas Sales and Services
For
information regarding factors that may affect the future results of operations
of our Competitive Natural Gas Sales and Services business segment, please read
“Risk Factors —
Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural
Gas Sales and Services, Interstate Pipelines and Field Services Business,” “ — Risk Factors
Associated with Our Consolidated Financial Condition” and “— Risks Common to Our
Business and Other Risks” in Item 1A of Part I of our 2008 Form
10-K.
The
following table provides summary data of our Competitive Natural Gas Sales and
Services business segment for the three months ended March 31, 2008 and
2009 (in millions, except throughput and customer data):
|
Three
Months Ended March 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
Revenues
|
$ | 1,120 | $ | 765 | ||||
|
Expenses:
|
||||||||
|
Natural
gas
|
1,105 | 752 | ||||||
|
Operation
and maintenance
|
8 | 10 | ||||||
|
Depreciation
and amortization
|
1 | 1 | ||||||
|
Taxes
other than income taxes
|
— | — | ||||||
|
Total
expenses
|
1,114 | 763 | ||||||
|
Operating
Income
|
$ | 6 | $ | 2 | ||||
|
Throughput
(in Bcf):
|
138 | 141 | ||||||
|
Number
of customers at period end
|
8,751 | 10,862 | ||||||
Three
months ended March 31, 2009 compared to three months ended March 31,
2008
Our
Competitive Natural Gas Sales and Services business segment reported operating
income of $2 million for the three months ended March 31, 2009
compared to $6 million for the three months ended March 31, 2008. The
decrease in operating income of $4 million was primarily due to a
$6 million write down of gas in the first quarter of 2009 to the lower of
cost or market as compared to no write down in the first quarter of 2008. 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. The unfavorable
impact of mark-to-market accounting for non-trading financial derivatives for
the first quarter of 2009 of $19 million versus $22 million for the
same period in 2008 accounted for a $3 million increase in operating
income.
Interstate
Pipelines
For
information regarding factors that may affect the future results of operations
of our Interstate Pipelines business segment, please read “Risk Factors — Risk Factors
Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and
Services, Interstate Pipelines and Field Services Businesses,” “ — Risk Factors
Associated with Our Consolidated Financial Condition” and “— Risks Common to Our
Business and Other Risks” in Item 1A of Part I of our 2008 Form
10-K.
The
following table provides summary data of our Interstate Pipelines business
segment for the three months ended March 31, 2008 and 2009 (in millions,
except throughput data):
|
Three
Months Ended March 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
Revenues
|
$ | 133 | $ | 153 | ||||
|
Expenses:
|
||||||||
|
Natural
gas
|
15 | 29 | ||||||
|
Operation
and maintenance
|
30 | 35 | ||||||
|
Depreciation
and amortization
|
12 | 12 | ||||||
|
Taxes
other than income taxes
|
5 | 8 | ||||||
|
Total
expenses
|
62 | 84 | ||||||
|
Operating
Income
|
$ | 71 | $ | 69 | ||||
|
Transportation
throughput (in Bcf)
|
424 | 467 | ||||||
Three
months ended March 31, 2009 compared to three months ended March 31,
2008
The
Interstate Pipeline business segment reported operating income of
$69 million for the three months ended March 31, 2009 compared to
$71 million for the same period of 2008. The decrease in
operating income of $2 million was primarily driven by higher operation and
maintenance expenses ($5 million) primarily related to costs associated
with incremental facilities and increased pension expense, and higher taxes
other than income ($3 million), $1 million of which was due to 2008
tax refunds. These increases are partially offset by increased
margins (revenues less natural gas costs) on Phase III of the Carthage to
Perryville pipeline that went into service in April 2008
($6 million).
Equity
Earnings. In addition, this business segment recorded equity
income (loss) of $5 million and $(2) million for the three months
ended March 31, 2008 and 2009, respectively, from its 50 percent
interest in the Southeast Supply Header (SESH), a jointly-owned pipeline that
went into service in September 2008. The $5 million income in the
first quarter of 2008 was pre-operating allowance for funds used during
construction in 2008. The $2 million loss in the first quarter of 2009
resulted from a non-cash charge of $5 million to reflect SESH’s decision to
discontinue the use of Statement of Financial Accounting Standards (SFAS) No.
71, “Accounting for the Effects of Certain Types of Regulation.” The
loss more than offset the equity income from SESH of $3 million for the first
quarter of 2009. These amounts are included in Equity in Earnings of
Unconsolidated Affiliates under the Other Income (Expense) caption.
Field
Services
For
information regarding factors that may affect the future results of operations
of our Field Services business segment, please read “Risk Factors — Risk Factors
Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and
Services, Interstate Pipelines and Field Services Businesses,” “ — Risk Factors
Associated with Our Consolidated Financial Condition” and “— Risks Common to Our
Business and Other Risks” in Item 1A of Part I of our 2008 Form
10-K.
The
following table provides summary data of our Field Services business segment for
the three months ended March 31, 2008 and 2009 (in millions, except
throughput data):
|
Three
Months Ended March 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
Revenues
|
$ | 58 | $ | 57 | ||||
|
Expenses:
|
||||||||
|
Natural
gas
|
(2 | ) | 7 | |||||
|
Operation
and maintenance
|
11 | 19 | ||||||
|
Depreciation
and amortization
|
3 | 4 | ||||||
|
Taxes
other than income taxes
|
1 | 1 | ||||||
|
Total
expenses
|
13 | 31 | ||||||
|
Operating
Income
|
$ | 45 | $ | 26 | ||||
|
Gathering
throughput (in Bcf)
|
98 | 104 | ||||||
Three
months ended March 31, 2009 compared to three months ended March 31,
2008
The Field
Services business segment reported operating income of $26 million for the
three months ended March 31, 2009 compared to $45 million for the same
period of 2008. The decrease in operating income of $19 million was
primarily driven by a one-time gain ($11 million) related to a settlement
and contract buyout of one of our customers and a one-time gain
($6 million) related to the sale of assets, both recognized in the first
quarter of 2008. The remaining decrease is due to a decrease in
commodity pricing offsetting the increase in margin relating to new
projects.
Equity
Earnings. In addition, this business segment recorded equity
income of $4 million and $2 million in the three months ended
March 31, 2008 and 2009, respectively, from its 50 percent interest in a
jointly-owned gas processing plant. The decrease is driven by a
decrease in liquids pricing. These amounts are included in Equity in
Earnings of Unconsolidated Affiliates under the Other Income (Expense)
caption.
CERTAIN
FACTORS AFFECTING FUTURE EARNINGS
For information on other
developments, factors and trends that may have an impact on our future
earnings, please read “Risk Factors” in Item 1A of Part I and
“Management’s Narrative Analysis of Results of Operations — Certain Factors
Affecting Future Earnings” in Item 7 of Part II of our 2008 Form 10-K and
“Cautionary Statement Regarding Forward-Looking Information.”
LIQUIDITY
AND CAPITAL RESOURCES
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 the
remaining nine months of 2009 include approximately $520 million of capital
expenditures.
We expect
that borrowings under our credit facility, anticipated cash flows from
operations and borrowings from affiliates 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.
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 Reliant Energy, Inc., now
known as RRI Energy, Inc., (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
23
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 March 31, 2009. RRI continues to meet
its obligations under the contracts, and, on the basis of current market
conditions, we and CenterPoint Energy believe that additional security is not
needed at this time. 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 exposure to the
counterparty under the guaranty.
Credit and Receivables
Facilities. As of April 30, 2009, we had the following
facilities (in millions):
|
Date
Executed
|
Type
of Facility
|
Size
of Facility
|
Amount
Utilized at
April
30, 2009
|
Termination
Date
|
|||||||
|
June
29, 2007
|
Revolver
|
$ | 950 | (1) | $ | 400 |
June
29, 2012
|
||||
|
November
25, 2008
|
Receivables
|
375 | 185 |
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 CERC
Corp.’s facility.
|
Our
$950 million credit facility’s first drawn cost is London Interbank Offered
Rate (LIBOR) plus 45 basis points based on our current credit
ratings. The facility contains a debt to total capitalization
covenant. Under our 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 this 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 each of
the credit facilities are subject to acceleration upon the occurrence of events
of default that we consider customary. We are currently in compliance with the
various business and financial covenants contained in the respective receivables
and credit facilities.
Our
$950 million credit facility backstops a $915 million commercial paper
program under which we began issuing commercial paper in February 2008. As of
April 30, 2009, there was $12 million of commercial paper
outstanding. As of April 30, 2009, our commercial paper is rated
“P-3” by Moody’s Investors Service, Inc. (Moody’s), “A-3” by Standard &
Poor’s Rating Services (S&P), 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 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.
Availability
under our 364-day receivables facility ranges from $128 million to
$375 million, reflecting seasonal changes in receivables
balances. At December 31, 2008 and March 31, 2009 the facility size
was $128 million and $375 million, respectively. As of December 31, 2008
and March 31, 2009, advances under the receivables facility were
$78 million and $215 million, respectively.
Securities Registered with the
SEC. As of April 30, 2009, we had a shelf registration
statement covering $500 million principal amount of senior debt
securities.
Temporary
Investments. As of April 30, 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 by CenterPoint Energy under
its revolving credit facility or the sale by CenterPoint Energy of its
commercial paper. At April 30, 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 April 30, 2009, Moody’s, S&P and Fitch had
assigned the following credit ratings to our senior unsecured debt:
|
Moody’s
|
S&P
|
Fitch
|
||||||||
|
Rating
|
Outlook
(1)
|
Rating
|
Outlook
(2)
|
Rating
|
Outlook
(3)
|
|||||
|
Baa3
|
Stable
|
BBB
|
Negative
|
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.
|
On April
30, 2009, S&P issued a report on CenterPoint Energy, CenterPoint Energy
Houston Electric, LLC and us. In its report, S&P affirmed the
senior long-term debt ratings of the three companies but revised its outlook to
negative from stable. S&P also lowered short-term corporate
credit and commercial paper program ratings for both CenterPoint Energy and us
to “A-3” from “A-2”.
A decline
in credit ratings could increase borrowing costs under our $950 million
revolving 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 our cash collateral
requirements and reduce our earnings.
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
March 31, 2009, the amount posted as collateral aggregated approximately
$292 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 one business days’ notice up to the amount of its previously
unsecured credit limit. We estimate that as of March 31, 2009, unsecured
credit limits extended to CES by counterparties aggregate $260 million;
however, utilized credit capacity was $83 million. 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
$158 million as of March 31, 2009, 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 April 30, 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 issuances. Debt 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 our customers to fulfill their payment obligations to
us;
|
|
|
•
|
the
ability of RRI and its subsidiaries and any successors to satisfy their
obligations to us, including indemity obligations, or in connection
with the contractual obligations to a third party pursuant to which we are
their 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;
|
|
|
•
|
system
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 our 2008 Form
10-K.
|
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.
NEW
ACCOUNTING PRONOUNCEMENTS
See Note
2 to our Interim Condensed Financial Statements for a discussion of new
accounting pronouncements that affect us.
Item 4T. 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 March 31, 2009 to provide assurance
that information required to be disclosed in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission’s rules and
forms and such information is accumulated and communicated to our management,
including our principal executive officer and principal financial officer, as
appropriate to allow timely decisions regarding disclosure.
There has
been no change in our internal controls over financial reporting that occurred
during the three months ended March 31, 2009 that has materially affected,
or is reasonably likely to materially affect, our internal controls over
financial reporting.
PART
II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
For a
discussion of material legal and regulatory proceedings affecting us, please
read Notes 4 and 11 to our Interim Condensed Financial Statements, each of which
is incorporated herein by reference. See also “Business — Regulation”
and “— Environmental Matters” in Item 1 and “Legal Proceedings” in Item 3 of our
2008 Form 10-K.
Item 1A. RISK FACTORS
There
have been no material changes from the risk factors disclosed in our 2008 Form
10-K.
Item 5. OTHER
INFORMATION
Our ratio
of earnings to fixed charges for the three months ended March 31, 2008 and
2009 was 4.84 and 3.64, respectively. We do not believe that the
ratios for these three-month periods are necessarily indicators of the ratios
for the twelve-month periods due to the seasonal nature of our
business. The ratios were calculated pursuant to applicable rules of
the Securities and Exchange Commission.
Item 6. Exhibits
The
following exhibits are filed herewith:
Exhibits
not incorporated by reference to a prior filing are designated by a cross (+);
all exhibits not so designated are incorporated by reference to a prior filing
as indicated.
Agreements
included as exhibits are included only to provide information to investors
regarding their terms. Agreements listed below may contain representations,
warranties and other provisions that were made, among other things, to provide
the parties thereto with specified rights and obligations and to allocate risk
among them, and no such agreement should be relied upon as constituting or
providing any factual disclosures about CenterPoint Energy Resources Corp., any
other persons, any state of affairs or other matters.
|
Exhibit
Number
|
Description
|
Report
or Registration
Statement
|
SEC
File or Registration Number
|
Exhibit
Reference
|
||||
|
3.1.1
|
–Certificate
of Incorporation of RERC Corp.
|
Form
10-K for the year ended December 31, 1997
|
1-13265
|
3(a)(1)
|
||||
|
3.1.2
|
–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
|
1-13265
|
3(a)(2)
|
||||
|
3.1.3
|
–Certificate
of Amendment changing the name to Reliant Energy Resources
Corp.
|
Form
10-K for the year ended December 31, 1998
|
1-13265
|
3(a)(3)
|
||||
|
3.1.4
|
–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)
|
||||
|
3.2
|
–Bylaws
of RERC Corp.
|
Form
10-K for the year ended December 31, 1997
|
1-13265
|
3(b)
|
||||
|
4.1
|
–$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
|
CERC
Corp.’s Form 10-Q for the quarter ended June 30, 2007
|
1-13265
|
4.1
|
||||
|
+12
|
|
|||||||
|
+31.1
|
|
|||||||
|
+31.2
|
|
|||||||
|
+32.1
|
|
|||||||
|
+32.2
|
|
|||||||
|
+99.1
|
|
SIGNATURES
Pursuant
to the requirements 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.
|
CENTERPOINT
ENERGY RESOURCES CORP.
|
|
|
By:
|
/s/
Walter L. Fitzgerald
|
|
Walter
L. Fitzgerald
|
|
|
Senior
Vice President and Chief Accounting Officer
|
|
Date: May
12, 2009
Index
to Exhibits
The
following exhibits are filed herewith:
Exhibits
not incorporated by reference to a prior filing are designated by a cross (+);
all exhibits not so designated are incorporated by reference to a prior filing
as indicated.
Agreements
included as exhibits are included only to provide information to investors
regarding their terms. Agreements listed below may contain representations,
warranties and other provisions that were made, among other things, to provide
the parties thereto with specified rights and obligations and to allocate risk
among them, and no such agreement should be relied upon as constituting or
providing any factual disclosures about CenterPoint Energy Resources Corp., any
other persons, any state of affairs or other matters.
|
Exhibit
Number
|
Description
|
Report
or Registration
Statement
|
SEC
File or Registration Number
|
Exhibit
Reference
|
||||
|
3.1.1
|
–Certificate
of Incorporation of RERC Corp
|
Form
10-K for the year ended December 31, 1997
|
1-13265
|
3(a)(1)
|
||||
|
3.1.2
|
–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
|
1-13265
|
3(a)(2)
|
||||
|
3.1.3
|
–Certificate
of Amendment changing the name to Reliant Energy Resources
Corp.
|
Form
10-K for the year ended December 31, 1998
|
1-13265
|
3(a)(3)
|
||||
|
3.1.4
|
–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)
|
||||
|
3.2
|
–Bylaws
of RERC Corp.
|
Form
10-K for the year ended December 31, 1997
|
1-13265
|
3(b)
|
||||
|
4.1
|
–$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
|
CERC
Corp.’s Form 10-Q for the quarter ended June 30, 2007
|
1-13265
|
4.1
|
||||
|
+12
|
|
|||||||
|
+31.1
|
|
|||||||
|
+31.2
|
|
|||||||
|
+32.1
|
|
|||||||
|
+32.2
|
|
|||||||
|
+99.1
|
|
30
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)
|
Three Months Ended
March 31,
|
||||||||
|
2008
|
2009
|
|||||||
|
Net
Income
|
$ | 126 | $ | 95 | ||||
|
Income
taxes
|
79 | 66 | ||||||
|
Capitalized
interest
|
(1 | ) | (1 | ) | ||||
| 204 | 160 | |||||||
|
Fixed
charges, as defined:
|
||||||||
|
Interest
|
48
|
58
|
||||||
|
Capitalized
interest
|
1
|
|
1
|
|||||
|
Interest component
of rentals charged to operating income
|
4
|
|
2
|
|||||
|
Total fixed
charges
|
53 | 61 | ||||||
|
Earnings,
as defined
|
$ | 257 | $ | 221 | ||||
|
Ratio
of earnings to fixed charges
|
4.84 | 3.64 | ||||||
Exhibit
31.1
CERTIFICATIONS
I, David
M. McClanahan, certify that:
1. I
have reviewed this quarterly report on Form 10-Q 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;
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|
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(c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
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|
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(d)
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Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
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5. The
registrant’s other certifying officer(s) and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
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(a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
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(b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
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Date: May
12, 2009
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/s/
David M. McClanahan
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David
M. McClanahan
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President
and Chief Executive
Officer
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Exhibit
31.2
CERTIFICATIONS
I, Gary
L. Whitlock, certify that:
1. I
have reviewed this quarterly report on Form 10-Q 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:
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(a)
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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;
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|
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(b)
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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;
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|
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(c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
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(d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
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5. The
registrant’s other certifying officer(s) and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
|
|
(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.
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Date: May
12, 2009
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/s/
Gary L. Whitlock
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|
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Gary
L. Whitlock
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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 Quarterly Report
of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the
quarter ended March 31, 2009 (the “Report”), as filed with the Securities and
Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive
Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge,
that:
1. The
Report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
2. The
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the Company.
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/s/
David M. McClanahan
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David
M. McClanahan
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President
and Chief Executive Officer
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May 12,
2009
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Exhibit
32.2
CERTIFICATION
PURSUANT TO
18 U.S.C.
SECTION 1350,
AS
ADOPTED PURSUANT TO SECTION 906
OF THE
SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report
of CenterPoint Energy Resources Corp. (the “Company”) on Form 10-Q for the
quarter ended March 31, 2009 (the “Report”), as filed with the Securities and
Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial
Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge,
that:
1. The
Report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
2. The
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the Company.
|
/s/
Gary L. Whitlock
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|
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Gary
L. Whitlock
|
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Executive
Vice President and Chief Financial Officer
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|
May 12,
2009
|
Exhibit
99.1
Item
1A. Risk
Factors
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 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.
1
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 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
2
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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·
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general
economic and capital market
conditions;
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·
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credit
availability from financial institutions and other
lenders;
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|
·
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investor
confidence in us and the markets in which we
operate;
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·
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maintenance
of acceptable credit ratings;
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·
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market
expectations regarding our future earnings and cash
flows;
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·
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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.
3
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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·
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our
payment of dividends;
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·
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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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·
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our
acquisition or disposition of
assets.
|
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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·
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restricting
the way we can handle or dispose of
wastes;
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4
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·
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limiting
or prohibiting construction activities in sensitive areas such as
wetlands, coastal regions, or areas inhabited by endangered
species;
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·
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requiring
remedial action to mitigate pollution conditions caused by our operations,
or attributable to former operations;
and
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·
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enjoining
the operations of facilities deemed in non-compliance with permits issued
pursuant to such environmental laws and
regulations.
|
In order
to comply with these requirements, we may need to spend substantial amounts and
devote other resources from time to time to:
|
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·
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construct
or acquire new equipment;
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·
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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.
|
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.
5
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.
6