cercform10-q.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
(Mark
One)
|
R
|
QUARTERLY REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
|
|
|
FOR
THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009
|
OR
|
£
|
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
|
Commission
file number 1-13265
CENTERPOINT
ENERGY RESOURCES CORP.
(Exact
name of registrant as specified in its charter)
Delaware
|
76-0511406
|
(State
or other jurisdiction of incorporation or organization)
|
(I.R.S.
Employer Identification No.)
|
|
|
1111
Louisiana
|
|
Houston,
Texas 77002
|
(713)
207-1111
|
(Address
and zip code of principal executive offices)
|
(Registrant’s
telephone number, including area
code)
|
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):
Large
accelerated filer o
|
Accelerated
filer o
|
Non-accelerated
filer þ
|
Smaller
reporting company o
|
|
|
(Do
not check if a smaller reporting company)
|
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes £ No R
As of
October 19, 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 SEPTEMBER 30, 2009
PART
I.
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FINANCIAL
INFORMATION
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Item
1.
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1
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Three
and Nine months Ended September 30, 2008 and 2009
(unaudited)
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1
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December
31, 2008 and September 30, 2009 (unaudited)
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2
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Nine
months Ended September 30, 2008 and 2009 (unaudited)
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4
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5
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Item
2.
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21
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Item 4T.
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31
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PART
II.
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|
OTHER
INFORMATION
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Item
1.
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31
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Item 1A.
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32
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Item
5.
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38
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Item
6.
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38
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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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state
and federal legislative and regulatory actions or developments, including
deregulation, re-regulation, environmental regulations, including
regulations related to global climate change and health care reform, and
changes in or application of laws or regulations applicable to the various
aspects of our business;
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•
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timely
and appropriate rate actions and increases, allowing recovery of costs and
a reasonable return on investment;
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•
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cost
overruns on major capital projects that cannot be recouped in
prices;
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•
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industrial,
commercial and residential growth in our service territory and changes in
market demand and demographic
patterns;
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•
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the
timing and extent of changes in commodity prices, particularly natural gas
and natural gas liquids;
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|
•
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the
timing and extent of changes in the supply of natural gas, including
supplies available for gathering by our field services
business;
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|
•
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the
timing and extent of changes in natural gas basis
differentials;
|
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•
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weather
variations and other natural
phenomena;
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•
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changes
in interest rates or rates of
inflation;
|
|
•
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commercial
bank and financial market conditions, our access to capital, the cost of
such capital, and the results of our financing and refinancing efforts,
including availability of funds in the debt capital
markets;
|
|
•
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actions
by rating agencies;
|
|
•
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effectiveness
of our risk management activities;
|
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•
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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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the
ability of RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc.
and Reliant Resources, Inc.) and its subsidiaries to satisfy their
obligations to us, including indemnity obligations, or in connection with
the contractual arrangements pursuant to which we are their
guarantor;
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|
•
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the
outcome of litigation brought by or against
us;
|
|
•
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our
ability to control costs;
|
|
•
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the
investment performance of CenterPoint Energy, 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;
|
|
•
|
acquisition
and merger activities involving our parent or our competitors;
and
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|
•
|
other
factors we discuss in “Risk Factors” in Item 1A of Part II of this
Quarterly Report on Form 10-Q and other reports we file from time to time
with the Securities and Exchange
Commission.
|
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)
|
|
Three
Months Ended
September 30,
|
|
|
Nine
months Ended
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
1,960 |
|
|
$ |
965 |
|
|
$ |
7,069 |
|
|
$ |
4,432 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
|
1,532 |
|
|
|
582 |
|
|
|
5,675 |
|
|
|
3,081 |
|
Operation
and maintenance
|
|
|
212 |
|
|
|
230 |
|
|
|
601 |
|
|
|
686 |
|
Depreciation
and amortization
|
|
|
54 |
|
|
|
58 |
|
|
|
163 |
|
|
|
172 |
|
Taxes
other than income taxes
|
|
|
33 |
|
|
|
31 |
|
|
|
129 |
|
|
|
126 |
|
Total
|
|
|
1,831 |
|
|
|
901 |
|
|
|
6,568 |
|
|
|
4,065 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
129 |
|
|
|
64 |
|
|
|
501 |
|
|
|
367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense):
Interest
and other finance charges
|
|
|
(51 |
) |
|
|
(52 |
) |
|
|
(148 |
) |
|
|
(159 |
) |
Equity
in earnings of unconsolidated affiliates
|
|
|
23 |
|
|
|
(3 |
) |
|
|
46 |
|
|
|
8 |
|
Other,
net
|
|
|
3 |
|
|
|
1 |
|
|
|
7 |
|
|
|
4 |
|
Total
|
|
|
(25 |
) |
|
|
(54 |
) |
|
|
(95 |
) |
|
|
(147 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Income Taxes
|
|
|
104 |
|
|
|
10 |
|
|
|
406 |
|
|
|
220 |
|
Income
tax expense
|
|
|
(37 |
) |
|
|
(5 |
) |
|
|
(153 |
) |
|
|
(86 |
) |
Net
Income
|
|
$ |
67 |
|
|
$ |
5 |
|
|
$ |
253 |
|
|
$ |
134 |
|
See Notes
to the Interim Condensed Consolidated Financial Statements
(AN
INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED
CONSOLIDATED BALANCE SHEETS
(Millions
of Dollars)
(Unaudited)
ASSETS
|
|
December
31,
2008
|
|
|
September 30,
2009
|
|
Current
Assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
1 |
|
|
$ |
1 |
|
Accounts
and notes receivable, net
|
|
|
774 |
|
|
|
331 |
|
Accrued
unbilled revenue
|
|
|
480 |
|
|
|
99 |
|
Accounts
and notes receivable – affiliated companies
|
|
|
9 |
|
|
|
15 |
|
Materials
and supplies
|
|
|
54 |
|
|
|
78 |
|
Natural
gas inventory
|
|
|
441 |
|
|
|
225 |
|
Non-trading
derivative assets
|
|
|
118 |
|
|
|
50 |
|
Taxes
receivable
|
|
|
— |
|
|
|
144 |
|
Deferred
tax asset, net
|
|
|
25 |
|
|
|
— |
|
Prepaid
expenses and other current assets
|
|
|
327 |
|
|
|
264 |
|
Total
current assets
|
|
|
2,229 |
|
|
|
1,207 |
|
|
|
|
|
|
|
|
|
|
Property,
Plant and Equipment:
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
|
6,313 |
|
|
|
6,743 |
|
Less
accumulated depreciation and amortization
|
|
|
950 |
|
|
|
1,081 |
|
Property,
plant and equipment, net
|
|
|
5,363 |
|
|
|
5,662 |
|
|
|
|
|
|
|
|
|
|
Other
Assets:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,696 |
|
|
|
1,696 |
|
Non-trading
derivative assets
|
|
|
20 |
|
|
|
15 |
|
Investment
in unconsolidated affiliates
|
|
|
345 |
|
|
|
471 |
|
Notes
receivable from unconsolidated affiliates
|
|
|
323 |
|
|
|
— |
|
Other
|
|
|
235 |
|
|
|
202 |
|
Total
other assets
|
|
|
2,619 |
|
|
|
2,384 |
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
10,211 |
|
|
$ |
9,253 |
|
See Notes
to the 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
|
|
December
31,
2008
|
|
|
September 30,
2009
|
|
Current
Liabilities:
|
|
|
|
|
|
|
Short-term
borrowings
|
|
$ |
153 |
|
|
$ |
40 |
|
Current
portion of long-term debt
|
|
|
7 |
|
|
|
7 |
|
Accounts
payable
|
|
|
722 |
|
|
|
282 |
|
Accounts
and notes payable — affiliated companies
|
|
|
33 |
|
|
|
270 |
|
Taxes
accrued
|
|
|
99 |
|
|
|
74 |
|
Interest
accrued
|
|
|
54 |
|
|
|
69 |
|
Customer
deposits
|
|
|
59 |
|
|
|
65 |
|
Non-trading
derivative liabilities
|
|
|
87 |
|
|
|
45 |
|
Other
|
|
|
302 |
|
|
|
235 |
|
Total
current liabilities
|
|
|
1,516 |
|
|
|
1,087 |
|
|
|
|
|
|
|
|
|
|
Other
Liabilities:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes, net
|
|
|
864 |
|
|
|
1,052 |
|
Non-trading
derivative liabilities
|
|
|
47 |
|
|
|
42 |
|
Benefit
obligations
|
|
|
114 |
|
|
|
108 |
|
Regulatory
liabilities
|
|
|
508 |
|
|
|
533 |
|
Other
|
|
|
101 |
|
|
|
142 |
|
Total
other liabilities
|
|
|
1,634 |
|
|
|
1,877 |
|
|
|
|
|
|
|
|
|
|
Long-term
Debt
|
|
|
3,712 |
|
|
|
2,805 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholder’s
Equity:
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
— |
|
|
|
— |
|
Paid-in
capital
|
|
|
2,416 |
|
|
|
2,416 |
|
Retained
earnings
|
|
|
935 |
|
|
|
1,069 |
|
Accumulated
other comprehensive loss
|
|
|
(2 |
) |
|
|
(1 |
) |
Total
stockholder’s equity
|
|
|
3,349 |
|
|
|
3,484 |
|
|
|
|
|
|
|
|
|
|
Total
Liabilities and Stockholder’s Equity
|
|
$ |
10,211 |
|
|
$ |
9,253 |
|
See Notes
to the Interim Condensed Consolidated Financial Statements
(AN
INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions
of Dollars)
(Unaudited)
|
|
Nine
months Ended September 30,
|
|
|
|
2008
|
|
|
2009
|
|
Cash
Flows from Operating Activities:
|
|
|
|
|
|
|
Net
income
|
|
$ |
253 |
|
|
$ |
134 |
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
163 |
|
|
|
172 |
|
Amortization of deferred
financing costs
|
|
|
7 |
|
|
|
7 |
|
Deferred income taxes
|
|
|
62 |
|
|
|
235 |
|
Write-down of natural gas
inventory
|
|
|
24 |
|
|
|
6 |
|
Equity in earnings of
unconsolidated affiliates, net of distributions
|
|
|
(45 |
) |
|
|
(4 |
) |
Changes in other assets and
liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable and unbilled revenues, net
|
|
|
469 |
|
|
|
819 |
|
Accounts
receivable/payable, affiliates
|
|
|
40 |
|
|
|
(8 |
) |
Inventory
|
|
|
(241 |
) |
|
|
186 |
|
Taxes
receivable
|
|
|
(26 |
) |
|
|
(144 |
) |
Accounts
payable
|
|
|
(118 |
) |
|
|
(440 |
) |
Fuel
cost over (under) recovery
|
|
|
(11 |
) |
|
|
(53 |
) |
Interest
and taxes accrued
|
|
|
(23 |
) |
|
|
(10 |
) |
Non-trading
derivatives, net
|
|
|
(22 |
) |
|
|
26 |
|
Margin
deposits, net
|
|
|
(96 |
) |
|
|
89 |
|
Other
current assets
|
|
|
20 |
|
|
|
23 |
|
Other
current liabilities
|
|
|
(16 |
) |
|
|
(2 |
) |
Other
assets
|
|
|
(1 |
) |
|
|
4 |
|
Other
liabilities
|
|
|
(37 |
) |
|
|
(10 |
) |
Other,
net
|
|
|
(33 |
) |
|
|
— |
|
Net
cash provided by operating activities
|
|
|
369 |
|
|
|
1,030 |
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(358 |
) |
|
|
(458 |
) |
Decrease
(increase) in notes receivable from unconsolidated
affiliates
|
|
|
(175 |
) |
|
|
323 |
|
Investment
in unconsolidated affiliates
|
|
|
(207 |
) |
|
|
(111 |
) |
Other,
net
|
|
|
34 |
|
|
|
(3 |
) |
Net
cash used in investing activities
|
|
|
(706 |
) |
|
|
(249 |
) |
|
|
|
|
|
|
|
|
|
Cash
Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
Decrease
in short-term borrowings, net
|
|
|
(82 |
) |
|
|
(113 |
) |
Long-term
revolving credit facility, net
|
|
|
595 |
|
|
|
(916 |
) |
Proceeds
from commercial paper, net
|
|
|
— |
|
|
|
15 |
|
Proceeds
from long-term debt
|
|
|
300 |
|
|
|
— |
|
Payments
of long-term debt
|
|
|
(307 |
) |
|
|
(6 |
) |
Increase
(decrease) in notes payable to affiliates
|
|
|
(67 |
) |
|
|
239 |
|
Debt
issuance costs
|
|
|
(2 |
) |
|
|
— |
|
Dividend
to parent
|
|
|
(100 |
) |
|
|
— |
|
Net
cash provided by (used in) financing activities
|
|
|
337 |
|
|
|
(781 |
) |
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
|
— |
|
|
|
— |
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1 |
|
|
|
1 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
1 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosure of Cash Flow Information:
|
|
|
|
|
|
|
|
|
Cash
Payments:
|
|
|
|
|
|
|
|
|
Interest,
net of capitalized interest
|
|
$ |
137 |
|
|
$ |
136 |
|
Income
taxes
|
|
|
148 |
|
|
|
18 |
|
Non-cash
transactions:
|
|
|
|
|
|
|
|
|
Accounts
payable related to capital expenditures
|
|
|
54 |
|
|
|
51 |
|
See Notes
to the Interim Condensed Consolidated Financial Statements
NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(1)
|
Background
and Basis of Presentation
|
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). 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. CERC
owns and operates natural gas distribution systems in six states. Subsidiaries
of CERC Corp. own interstate natural gas pipelines and gas gathering systems and
provide various ancillary services. A wholly owned subsidiary of CERC Corp.
offers variable and fixed-price physical natural gas supplies primarily to
commercial and industrial customers and electric and gas utilities.
CERC
Corp. 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 (GAAP) 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.
CERC’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 CERC’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 CERC’s reportable business segments, see Note 14.
(2)
|
New
Accounting Pronouncements
|
Effective
January 1, 2009, CERC adopted new accounting guidance which requires enhanced
disclosures of derivative instruments and hedging activities such as the fair
value of derivative instruments and presentation of their gains or losses in
tabular format, as well as disclosures regarding credit risks and strategies and
objectives for using derivative instruments. These disclosures are
included as part of CERC’s Derivative Instruments footnote (see Note
5).
In
December 2008, the FASB issued new accounting guidance on employers' disclosures
about postretirement benefit plan assets which expands the disclosures about
employers’ plan assets to include more detailed disclosures about the employers’
investment strategies, major categories of plan assets, concentrations of risk
within plan assets and valuation techniques used to measure the fair value of
plan assets. This new accounting guidance is effective for fiscal years ending
after December 15, 2009. CERC expects that the adoption of this new guidance
will not have a material impact on its financial position, results of operations
or cash flows.
In April
2009, the FASB issued new accounting guidance on interim disclosures about fair
value of financial instruments which expands the fair value disclosures required
for all financial instruments to interim periods. This new guidance also
requires entities to disclose in interim periods the methods and significant
assumptions used to estimate the fair value of financial instruments. This new
accounting guidance is effective for interim reporting periods ending after June
15, 2009. CERC’s adoption of this new guidance did not have a material impact on
its financial position, results of operations or cash flows. See Note
13 for the required disclosures.
In May
2009, the FASB issued new accounting guidance on subsequent events that
establishes general standards of accounting for and disclosure of events that
occur after the balance sheet date but before financial statements are issued or
are available to be issued. This new accounting guidance is effective for
interim or annual periods ending after June 15, 2009. CERC’s adoption of this
new guidance did not have a material impact on its financial position, results
of operations or cash flows. See Note 16 for the subsequent event related
disclosures.
In June
2009, the FASB issued new accounting guidance on consolidation of variable
interest entities (VIEs) that changes how a reporting entity determines a
primary beneficiary that would consolidate the VIE from a quantitative risk and
rewards approach to a qualitative approach based on which variable interest
holder has the power to direct the economic performance related activities of
the VIE as well as the obligation to absorb losses or right to receive benefits
that could potentially be significant to the VIE. This new guidance requires the
primary beneficiary assessment to be performed on an ongoing basis and also
requires enhanced disclosures that will provide more transparency about a
company’s involvement in a VIE. This new guidance is effective for a reporting
entity’s first annual reporting period that begins after November 15,
2009. CERC expects that the adoption of this new guidance will not have a
material impact on its financial position, results of operations or cash
flows.
In June
2009, the FASB issued new accounting guidance on the FASB Accounting Standards
Codification (Codification) and the hierarchy of generally accepted accounting
principles. This new accounting guidance establishes the Codification
as the source of authoritative U.S. generally accepted accounting principles
recognized by the FASB to be applied by nongovernmental entities. Rules and
interpretive releases of the Securities and Exchange Commission (SEC) under
authority of federal securities laws are also sources of authoritative GAAP for
SEC registrants. This new accounting guidance is effective for financial
statements issued for interim and annual periods ending after September 15,
2009. CERC’s adoption of this new guidance did not have any impact on its
financial position, results of operations or cash flows.
Management
believes the impact of other recently issued standards, which are not yet
effective, will not have a material impact on CERC’s consolidated financial
position, results of operations or cash flows upon adoption.
(3)
|
Employee
Benefit Plans
|
CERC’s
employees participate in CenterPoint Energy’s postretirement benefit plan.
CERC’s net periodic cost includes the following components relating to
postretirement benefits:
|
|
Three
Months Ended
September 30,
|
|
|
Nine
months Ended
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
|
(in
millions)
|
|
Interest
cost
|
|
$ |
2 |
|
|
$ |
2 |
|
|
$ |
6 |
|
|
$ |
6 |
|
Expected
return on plan assets
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
Amortization
of prior service cost
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
2 |
|
Net
periodic cost
|
|
$ |
2 |
|
|
$ |
2 |
|
|
$ |
7 |
|
|
$ |
7 |
|
CERC
expects to contribute approximately $16 million to CenterPoint Energy’s
postretirement benefit plan in 2009, of which $4 million and
$12 million, respectively, have been contributed during the three and nine
months ended September 30, 2009.
(a)
Rate Proceedings
Texas. In March 2008, the
natural gas distribution businesses of CERC (Gas Operations) filed a request to
change its rates with the Railroad Commission of Texas (Railroad Commission) and
the 47 cities in its Texas Coast service territory, an area consisting of
approximately 230,000 customers in cities and communities on the outskirts of
Houston. In 2008, Gas Operations implemented rates that are expected to increase
annual revenues by approximately $3.5 million. The implemented rates
have been contested by 9 cities. CERC does not expect the outcome of this matter
to have a material adverse impact on its financial condition, results of
operations or cash flows.
In July
2009, Gas Operations filed a request to change its rates with the Railroad
Commission and the 29 cities in its Houston service territory, consisting of
approximately 940,000 customers in and around Houston. The request seeks to
establish uniform rates, charges and terms and conditions of service for the
cities and environs of the Houston service territory. If approved by the
Railroad Commission and the cities, the proposed new rates would result in an
overall increase in annual revenue of $25.4 million. The proposed
increase would allow Gas Operations to recover increased operating costs, which
include higher pension expense. It would also provide a return on the
additional capital invested to serve its customers. In addition, Gas
Operations is seeking an adjustment mechanism similar to that obtained in the
Texas Coast rate proceeding discussed above that would annually adjust rates to
reflect changes in capital, expenses and usage. CERC does not expect an order
from the Railroad Commission and the cities until the first quarter of
2010.
Minnesota. In November 2006,
the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas
Operations for a waiver of MPUC rules in order to allow Gas Operations to
recover approximately $21 million in unrecovered purchased gas costs
related to periods prior to July 1, 2004. Those unrecovered gas costs were
identified as a result of revisions to previously approved calculations of
unrecovered purchased gas costs. Following that denial, Gas Operations recorded
a $21 million adjustment to reduce pre-tax earnings in the fourth quarter
of 2006 and reduced the regulatory asset related to these costs by an equal
amount. In March 2007, following the MPUC’s denial of reconsideration of its
ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of
the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been
arbitrary and capricious in denying Gas Operations a waiver. The court ordered
the case remanded to the MPUC for reconsideration under the same principles the
MPUC had applied in previously granted waiver requests. The MPUC sought further
review of the court of appeals decision from the Minnesota Supreme Court, and in
July 2008, the Minnesota Supreme Court agreed to review the
decision. In July 2009, the Minnesota Supreme Court issued its
decision in which it reversed the decision of the Minnesota Court of Appeals and
upheld the MPUC’s decision to deny the requested variance. The court’s decision
had no negative impact on CERC’s financial condition, results of operations or
cash flows, as the costs at issue were written off at the time they were
disallowed.
In
November 2008, Gas Operations filed a request with the MPUC to increase its
rates for utility distribution service. 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, higher pension 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 on 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. CERC does not expect an order from the MPUC until early
2010.
Mississippi. In July 2009,
Gas Operations filed a request with the Mississippi Public Service Commission
(MPSC) to increase its rates by $6.2 million annually. In October
2009, the MPSC issued an order whereby Gas Operations would retain 100% of the
benefits of an asset management agreement covering Mississippi pipeline and gas
storage capacity, withdraw its request to increase base rates and not file
another general rate increase, with certain exceptions, prior to July 1,
2011.
(b)
Regulatory Accounting
CERC has
a 50% ownership interest in Southeast Supply Header, LLC (SESH) which owns and
operates a 270-mile interstate natural gas pipeline. In 2009, SESH
discontinued the use of guidance for accounting for regulated operations, which
resulted in CERC recording its share of the effects of such write-offs of SESH’s
regulatory assets through non-cash pre-tax charges for the quarters ended March
31, 2009 and September 30, 2009 of $5 million and $11 million,
respectively. These non-cash charges are reflected in equity in
earnings of unconsolidated affiliates in the Condensed Statements of
Consolidated Income. The related tax benefits of $2 million and
$4 million, respectively, are reflected in the income tax expense line of
the Condensed Statements of Consolidated Income.
(5)
|
Derivative
Instruments
|
CERC is
exposed to various market risks. These risks arise from transactions entered
into in the normal course of business. CERC utilizes derivative
instruments such as physical forward contracts, swaps and options to mitigate
the impact of changes in commodity prices and weather on its operating results
and cash flows. Such derivatives are recognized in CERC’s Condensed Consolidated
Balance Sheets at their fair value unless CERC elects the normal purchase and
sales exemption for qualified physical transactions. A derivative 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.
In prior
years, CERC entered into certain derivative instruments that were designated as
cash flow hedges. The objective of these derivative instruments was to hedge the
price risk associated with natural gas purchases and sales to reduce cash flow
variability related to meeting CERC’s wholesale and retail customer
obligations. If derivatives are designated as a cash flow hedge, the
effective portions of the changes in their fair values are reflected initially
as a separate component of stockholder’s 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 derivatives not designated as
normal or as cash flow hedges are recognized in income as they occur. CERC 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 CERC’s marketing, risk management services and hedging activities. The
committee’s duties are to establish CERC’s commodity risk policies, allocate
board-approved commercial risk limits, approve use of new products and
commodities, monitor positions and ensure compliance with CERC’s risk management
policies and procedures and limits established by CenterPoint Energy’s board of
directors.
CERC’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. CERC
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. CERC 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 September 30, 2008, CERC recorded increased natural
gas revenues from unrealized net gains of $80 million and increased natural
gas expense from unrealized net losses of $34 million, resulting in a net
unrealized gain of $46 million. During the three months ended
September 30, 2009, CERC recorded decreased natural gas revenues from
unrealized net losses of $37 million and decreased natural gas expense from
unrealized net gains of $31 million, resulting in a net unrealized loss of
$6 million.
During
the nine months ended September 30, 2008, CERC recorded increased natural
gas revenues from unrealized net gains of $51 million and increased natural
gas expense from unrealized net losses of $37 million, resulting in a net
unrealized gain of $14 million. During the nine months ended
September 30, 2009, CERC recorded decreased natural gas revenues from
unrealized net losses of $71 million and decreased natural gas expense from
unrealized net gains of $49 million, resulting in a net unrealized loss of
$22 million.
Weather
Hedges. CERC 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 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,
2008 and 2009, CERC entered into heating-degree day swaps to mitigate the effect
of fluctuations from normal weather on its financial position and cash flows for
the respective winter heating seasons. The swaps were based on
ten-year normal weather. During the three and nine months ended
September 30, 2008, CERC recognized losses of $-0- and
$13 million, respectively, related to these swaps. During the
three and nine months ended September 30, 2009, CERC
recognized
losses of
$-0- and $3 million, respectively, related to these swaps. The
losses were substantially offset by increased revenues due to colder than normal
weather. Weather hedge 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 CERC’s derivative instruments and
hedging activities. The first table provides a balance sheet overview
of CERC’s Derivative Assets and Liabilities as of September 30, 2009, while
the latter tables provide a breakdown of the related income statement impact for
the three and nine months ended September 30, 2009.
Fair
Value of Derivative Instruments
|
|
|
|
September
30, 2009
|
|
Total
derivatives not designated as hedging
instruments
|
|
Balance
Sheet
Location
|
|
Derivative
Assets
Fair
Value (2) (3)
|
|
Derivative
Liabilities
Fair
Value (2) (3)
|
|
|
|
|
|
(in
millions)
|
|
Commodity
contracts (1)
|
|
Current
Assets
|
|
$ |
59 |
|
$ |
(9 |
) |
Commodity
contracts (1)
|
|
Other
Assets
|
|
|
16 |
|
|
(1 |
) |
Commodity
contracts (1)
|
|
Current
Liabilities
|
|
|
26 |
|
|
(137 |
) |
Commodity
contracts (1)
|
|
Other
Liabilities
|
|
|
2 |
|
|
(94 |
) |
Total
|
|
$ |
103 |
|
$ |
(241 |
) |
_______
|
(1)
|
Commodity
contracts are subject to master netting arrangements and are presented on
a net basis in the Condensed Consolidated Balance Sheets. This netting
causes derivative assets (liabilities) to be ultimately presented net in a
liability (asset) account within the Condensed Consolidated Balance
Sheets.
|
|
(2)
|
The
fair value shown for commodity contracts is comprised of derivative gross
volumes totaling 668 billion cubic feet (Bcf) or a net 138 Bcf long
position. Of the net long position, basis swaps constitute 61
Bcf and volumes associated with price stabilization activities of the
Natural Gas Distribution business segment comprise 56
Bcf.
|
|
(3)
|
The
net of total non-trading derivative assets and liabilities is a
$22 million liability as shown on CERC’s Condensed Consolidated
Balance Sheets, and is comprised of the commodity contracts derivative
assets and liabilities separately shown above offset by collateral netting
of $116 million.
|
For
CERC’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
|
|
Income
Statement Location
|
|
Three
Months
Ended
September
30, 2009
|
|
|
|
|
|
(in
millions)
|
|
Commodity
contracts
|
|
Gains
(Losses) in Revenue
|
|
$ |
(4 |
) |
Commodity
contracts (1)
|
|
Gains
(Losses) in Expense: Natural Gas
|
|
|
(27 |
) |
Total
|
|
$ |
(31 |
) |
_________
|
(1)
|
The
Gains (Losses) in Expense: Natural Gas includes $(31) million of
costs associated with price stabilization activities of the Natural Gas
Distribution business segment that will be ultimately recovered through
purchased gas adjustments.
|
Income
Statement Impact of Derivative Activity
|
|
Total
derivatives not designated as hedging
instruments
|
|
Income
Statement Location
|
|
Nine
Months
Ended
September
30, 2009
|
|
|
|
|
|
(in
millions)
|
|
Commodity
contracts
|
|
Gains
(Losses) in Revenue
|
|
$ |
80 |
|
Commodity
contracts (1)
|
|
Gains
(Losses) in Expense: Natural Gas
|
|
|
(218 |
) |
Total
|
|
$ |
(138 |
) |
_________
|
(1)
|
The
Gains (Losses) in Expense: Natural Gas includes $(148) million of
costs associated with price stabilization activities of the Natural Gas
Distribution business segment that will be ultimately recovered through
purchased gas adjustments.
|
(c)
Credit Risk Contingent Features
CERC
enters into financial derivative contracts containing material adverse change
provisions. These provisions require CERC to post additional
collateral if the Standard & Poor’s Rating Services or Moody’s Investors
Service, Inc. credit rating of CERC is downgraded. The total fair
value of the derivative instruments that contain credit risk contingent features
that are in a net liability position at September 30, 2009 is
$151 million. The aggregate fair value of assets that are
already posted as collateral at September 30, 2009 is
$82 million. If all derivative contracts (in a net liability
position) containing credit risk contingent features were triggered at
September 30, 2009, $69 million of additional assets would be required
to be posted as collateral.
(6)
|
Fair
Value Measurements
|
Effective
January 1, 2008, CERC adopted new accounting guidance on fair value
measurements which requires additional disclosures about CERC’s financial assets
and liabilities that are measured at fair value. Effective January 1,
2009, CERC adopted this new guidance for nonfinancial assets and liabilities,
which adoption had no impact on CERC’s financial position, results of operations
or cash flows. Beginning in January 2008, assets and liabilities
recorded at fair value in the Condensed Consolidated Balance Sheets are
categorized based upon the level of judgment associated with the inputs used to
measure their value. Hierarchical levels, as defined in this guidance and
directly related to the amount of subjectivity associated with the inputs to
fair valuations of these assets and liabilities, are as follows:
Level 1:
Inputs are unadjusted quoted prices in active markets for identical assets or
liabilities at the measurement date. The types of assets carried at Level 1
fair value generally are financial derivatives, investments and equity
securities listed in active markets.
Level 2:
Inputs, other than quoted prices included in Level 1, are observable for the
asset or liability, either directly or indirectly. Level 2 inputs include quoted
prices for similar instruments in active markets, and inputs other than quoted
prices that are observable for the asset or liability. Fair value assets
and liabilities that are generally included in this category are derivatives
with fair values based on inputs from actively quoted markets.
Level 3:
Inputs are unobservable for the asset or liability, and include situations where
there is little, if any, market activity for the asset or liability. In certain
cases, the inputs used to measure fair value may fall into different levels of
the fair value hierarchy. In such cases, the level in the fair value hierarchy
within which the fair value measurement in its entirety falls has been
determined based on the lowest level input that is significant to the fair value
measurement in its entirety. Unobservable inputs reflect CERC’s judgments about
the assumptions market participants would use in pricing the asset or liability
since limited market data exists. CERC develops these inputs based on the best
information available, including CERC’s own data. CERC’s Level 3
derivative instruments primarily consist of options that are not traded on
recognized exchanges and are valued using option pricing models.
The
following tables present information about CERC’s assets and liabilities
(including derivatives that are presented net) measured at fair value on a
recurring basis as of December 31, 2008 and September 30, 2009, and
indicate the fair value hierarchy of the valuation techniques utilized by CERC
to determine such fair value.
|
|
Quoted
Prices in
Active
Markets
for Identical
Assets
(Level
1)
|
|
|
Significant
Other
Observable
Inputs
(Level
2)
|
|
|
Significant
Unobservable
Inputs
(Level
3)
|
|
|
Netting
Adjustments (1)
|
|
|
Balance
as
of
December
31,
2008
|
|
|
|
(in
millions)
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
equities
|
|
$ |
1 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
1 |
|
Investments,
including money
market
funds
|
|
|
11 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
11 |
|
Derivative
assets
|
|
|
8 |
|
|
|
155 |
|
|
|
49 |
|
|
|
(74 |
) |
|
|
138 |
|
Total
assets
|
|
$ |
20 |
|
|
$ |
155 |
|
|
$ |
49 |
|
|
$ |
(74 |
) |
|
$ |
150 |
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
liabilities
|
|
$ |
44 |
|
|
$ |
244 |
|
|
$ |
107 |
|
|
$ |
(261 |
) |
|
$ |
134 |
|
Total
liabilities
|
|
$ |
44 |
|
|
$ |
244 |
|
|
$ |
107 |
|
|
$ |
(261 |
) |
|
$ |
134 |
|
__________
|
(1)
|
Amounts
represent the impact of legally enforceable master netting agreements that
allow CERC to settle positive and negative positions and also include cash
collateral held or placed with the same
counterparties.
|
|
|
Quoted
Prices in
Active
Markets
for Identical
Assets
(Level
1)
|
|
|
Significant
Other
Observable
Inputs
(Level
2)
|
|
|
Significant
Unobservable
Inputs
(Level
3)
|
|
|
Netting
Adjustments (1)
|
|
|
Balance
as
of
September
30,
2009
|
|
|
|
(in
millions)
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
equities
|
|
$ |
1 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
1 |
|
Investments,
including money
market
funds
|
|
|
11 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
11 |
|
Derivative
assets
|
|
|
2 |
|
|
|
94 |
|
|
|
7 |
|
|
|
(38 |
) |
|
|
65 |
|
Total
assets
|
|
$ |
14 |
|
|
$ |
94 |
|
|
$ |
7 |
|
|
$ |
(38 |
) |
|
$ |
77 |
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
liabilities
|
|
$ |
16 |
|
|
$ |
207 |
|
|
$ |
18 |
|
|
$ |
(154 |
) |
|
$ |
87 |
|
Total
liabilities
|
|
$ |
16 |
|
|
$ |
207 |
|
|
$ |
18 |
|
|
$ |
(154 |
) |
|
$ |
87 |
|
__________
|
(1)
|
Amounts
represent the impact of legally enforceable master netting agreements that
allow CERC to settle positive and negative positions and also include cash
collateral of $116 million posted with the same
counterparties.
|
The
following tables present additional information about assets or liabilities,
including derivatives that are measured at fair value on a recurring basis for
which CERC has utilized Level 3 inputs to determine fair value:
|
|
Fair
Value Measurements Using Significant Unobservable Inputs (Level
3)
|
|
|
|
Derivative
assets and liabilities, net
|
|
|
|
Three
Months Ended September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in
millions)
|
|
Beginning
balance
|
|
$ |
6 |
|
|
$ |
(17 |
) |
Total
unrealized gains or (losses):
|
|
|
|
|
|
|
|
|
Included
in earnings
|
|
|
(61 |
) |
|
|
2 |
|
Included
in regulatory assets
|
|
|
— |
|
|
|
3 |
|
Purchases,
sales, other settlements, net
|
|
|
(4 |
) |
|
|
1 |
(1) |
Ending
balance
|
|
$ |
(59 |
) |
|
$ |
(11 |
) |
The
amount of total gains for the period included in earnings
attributable
to the change in unrealized gains or losses relating to
assets
still held at the reporting date
|
|
$ |
4 |
|
|
$ |
3 |
|
__________
(1)
|
Purchases,
sales, other settlements, net include a less than $1 million gain
associated with price stabilization activities of CERC’s Natural Gas
Distribution business segment.
|
|
|
Fair
Value Measurements Using Significant Unobservable Inputs (Level
3)
|
|
|
|
Derivative
assets and liabilities, net
|
|
|
|
Nine
Months Ended September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in
millions)
|
|
Beginning
balance
|
|
$ |
(3 |
) |
|
$ |
(58 |
) |
Total
unrealized gains or (losses):
|
|
|
|
|
|
|
|
|
Included
in earnings
|
|
|
(52 |
) |
|
|
— |
|
Included
in regulatory assets
|
|
|
— |
|
|
|
(13 |
) |
Purchases,
sales, other settlements, net
|
|
|
(4 |
) |
|
|
60 |
(1) |
Ending
balance
|
|
$ |
(59 |
) |
|
$ |
(11 |
) |
The
amount of total gains for the period included in earnings
attributable
to the change in unrealized gains or losses relating to
assets
still held at the reporting date
|
|
$ |
9 |
|
|
$ |
2 |
|
_________
|
(1)
|
Purchases,
sales, other settlements, net include a $57 million gain associated
with price stabilization activities of CERC’s Natural Gas Distribution
business segment.
|
Goodwill
by reportable business segment as of both December 31, 2008 and
September 30, 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 |
|
CERC
performs its goodwill impairment tests at least annually and evaluates goodwill
when events or changes in circumstances indicate that the carrying value of
these assets may not be recoverable. The impairment evaluation for goodwill is
performed by using a two-step process. In the first step, the fair value of each
reporting unit is compared with the carrying amount of the reporting unit,
including goodwill. The estimated fair value of the reporting unit
is
generally
determined on the basis of discounted future cash flows. If the estimated fair
value of the reporting unit is less than the carrying amount of the reporting
unit, then a second step must be completed in order to determine the amount of
the goodwill impairment that should be recorded. In the second step, the implied
fair value of the reporting unit’s goodwill is determined by allocating the
reporting unit’s fair value to all of its assets and liabilities other than
goodwill (including any unrecognized intangible assets) in a manner similar to a
purchase price allocation. The resulting implied fair value of the goodwill that
results from the application of this second step is then compared to the
carrying amount of the goodwill and an impairment charge is recorded for the
difference.
CERC
performed the test at July 1, 2009, its annual impairment testing date, and
determined that no impairment charge for goodwill was required.
The
following table summarizes the components of total comprehensive income (net of
tax):
|
|
For
the Three Months Ended
September 30,
|
|
For
the Nine Months Ended
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
2008
|
|
|
2009
|
|
|
|
(in
millions)
|
|
Net
income
|
|
$ |
67 |
|
|
$ |
5 |
|
$ |
253 |
|
|
$ |
134 |
|
Other
comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustment
to pension and other postretirement
plans
(net of tax of $1, $-0-, $1 and $1)
|
|
|
(1 |
) |
|
|
— |
|
|
(1 |
) |
|
|
1 |
|
Reclassification
of deferred gain from cash flow
hedges
realized in net income (net of tax of $-0-,
$-0-,$2,
$-0-)
|
|
|
(1 |
) |
|
|
— |
|
|
(5 |
) |
|
|
— |
|
Other
comprehensive income (loss)
|
|
|
(2 |
) |
|
|
— |
|
|
(6 |
) |
|
|
1 |
|
Comprehensive
income
|
|
$ |
65 |
|
|
$ |
5 |
|
$ |
247 |
|
|
$ |
135 |
|
The
following table summarizes the components of accumulated other comprehensive
loss:
|
|
December
31,
2008
|
|
|
September 30,
2009
|
|
|
|
(in
millions)
|
|
Adjustment
to pension and other postretirement plans
|
|
|
(2 |
) |
|
|
(1 |
) |
Total
accumulated other comprehensive income
|
|
$ |
(2 |
) |
|
$ |
(1 |
) |
(9)
|
Related
Party Transactions
|
CERC
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 September 30, 2009, CERC had
borrowings from the money pool of $-0- and $239 million,
respectively.
For both
the three months ended September 30, 2008 and 2009, CERC had net interest
expense related to affiliate borrowings of less than $1 million. For the
nine months ended September 30, 2008 and 2009, CERC had net interest
expense related to affiliate borrowings of approximately $1 million and
less than $1 million, respectively.
CenterPoint
Energy provides some corporate services to CERC. The costs of services have been
charged directly to CERC 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 CERC
not been an affiliate. Amounts charged to CERC for these services were
$35 million and $39 million for the three months ended
September 30, 2008 and 2009, respectively, and $105 million and
$115 million for the nine months ended September 30, 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 October 9, 2009, CERC amended its receivables
facility to extend the termination date to October 8,
2010. Availability under CERC’s 364-day receivables facility now
ranges from $150 million to $375 million, reflecting seasonal changes
in receivables balances. As of December 31, 2008 and
September 30, 2009, the facility size was $128 million and
$150 million, respectively. As of December 31, 2008 and
September 30, 2009, advances under the receivables facilities were
$78 million and $40 million, respectively.
Inventory Financing. In
December 2008, CERC 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 September 30,
2009, CERC’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. On October 7, 2009, the size of the CERC Corp.
revolving credit facility was reduced from $950 million to
$915 million through removal of Lehman Brothers Bank, FSB (Lehman) as a
lender. Prior to its removal, Lehman had a $35 million
commitment to lend. All credit facility loans to CERC Corp. that were
funded by Lehman were repaid in September 2009. CERC Corp.’s
$915 million credit facility’s first drawn cost is the London Interbank
Offered Rate (LIBOR) plus 45 basis points based on CERC Corp.’s current credit
ratings. The facility contains a debt to total capitalization
covenant.
Under
CERC Corp.’s $915 million credit facility, an additional utilization fee of
5 basis points applies to borrowings any time more than 50% of the facility is
utilized. The spread to LIBOR and the utilization fee fluctuate based on CERC
Corp.’s credit rating.
As of
December 31, 2008 and September 30, 2009, CERC Corp. had $926 million
and $10 million, respectively, of borrowings under its $915 million
credit facility. There was $-0- and $15 million of outstanding
commercial paper backstopped by CERC Corp.’s credit facility as of December 31,
2008 and September 30, 2009, respectively. CERC Corp. was in
compliance with all debt covenants as of September 30, 2009.
(11)
|
Commitments
and Contingencies
|
(a)
Natural Gas Supply Commitments
Natural
gas supply commitments include natural gas contracts related to CERC’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 CERC’s Condensed
Consolidated Balance Sheets as of December 31, 2008 and September 30,
2009 as these contracts meet the exception to be classified as "normal purchases
contracts" or do not meet the definition of a derivative. Natural gas supply
commitments also include natural gas transportation contracts that do not meet
the definition of a derivative. As of September 30, 2009, minimum payment
obligations for natural gas supply commitments are approximately
$151 million for the remaining three months in 2009, $449 million in
2010, $466 million in 2011, $383 million in 2012, $371 million in
2013 and $738 million after 2013.
(b)
Capital Commitments
In
September 2009, CenterPoint Energy Field Services, Inc. (CEFS), a wholly-owned
natural gas gathering and treating subsidiary of CERC Corp., entered into
long-term agreements with an indirect wholly-owned subsidiary of EnCana
Corporation (EnCana) and an indirect wholly-owned subsidiary of Royal Dutch
Shell plc (Shell) to provide gathering and treating services for their natural
gas production from the Haynesville Shale and Bossier Shale formations in Texas
and Louisiana. CEFS has also acquired existing jointly-owned gathering
facilities from EnCana and Shell in De Soto and Red River parishes in northwest
Louisiana.
Under the
terms of the agreements, CEFS commenced gathering and treating services
immediately utilizing the acquired facilities. CEFS will also expand the
acquired facilities to gather and treat up to 700 million cubic feet (MMcf)
per day of natural gas from their current throughput of over 100 MMcf per day.
If EnCana or Shell elect, CEFS will further expand the facilities in order to
gather and treat additional future volumes.
New
construction to reach capacity of 700 MMcf per day includes more than 200 miles
of pipelines, nearly 25,500 horsepower of compression and over 800 MMcf per day
of treating capacity.
Each of
the agreements includes volume commitments for which CEFS has exclusive rights
to gather Shell’s and EnCana’s natural gas production.
CEFS
estimates that the purchase of existing facilities and construction to gather
700 MMcf per day will cost up to $325 million. If EnCana and Shell elect
expansion of the project to gather and process additional future volumes of up
to 1 billion cubic feet per day, CEFS estimates that the expansion would cost as
much as an additional $300 million and EnCana and Shell would provide
incremental volume commitments.
(c)
Legal, Environmental and Other Regulatory Matters
Legal
Matters
Gas Market Manipulation
Cases. CenterPoint Energy or its predecessor, Reliant Energy,
Incorporated (Reliant Energy), and certain of its former subsidiaries are named
as defendants in several lawsuits described below. Under a master separation
agreement between CenterPoint Energy and RRI (formerly known as Reliant
Resources, Inc. and Reliant Energy, Inc.), CenterPoint Energy and its
subsidiaries are entitled to be indemnified by RRI for any losses, including
attorneys’ fees and other costs, arising out of these
lawsuits. Pursuant to the indemnification obligation, RRI is
defending CenterPoint Energy and its subsidiaries to the extent named in these
lawsuits. A large number of lawsuits were filed against numerous gas
market participants in a number of federal and western state courts in
connection with the operation of the natural gas markets in 2000-2002.
CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in
the California and Western markets. These lawsuits, many of which have been
filed as class actions, allege violations of state and federal antitrust laws.
Plaintiffs in these lawsuits are seeking a variety of forms of relief,
including, among others, recovery of compensatory damages (in some cases in
excess of $1 billion), a trebling of compensatory damages, full
consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant
Energy were named in approximately 30 of these lawsuits, which were instituted
between 2003 and 2009. CenterPoint Energy and its affiliates have been released
or dismissed from all but two of such cases. CenterPoint Energy Services, Inc.
(CES), a subsidiary of CERC Corp., is a defendant in a case now pending in
federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas
prices in 2000-2002. Additionally, CenterPoint Energy was a defendant
in a lawsuit filed in state court in Nevada that was dismissed in 2007, but the
plaintiffs have indicated that they will appeal the dismissal. CenterPoint
Energy believes that neither it nor CES is a proper defendant in these remaining
cases and will continue to pursue dismissal from those cases. CERC
does not expect the ultimate outcome of these remaining matters to have a
material impact on its financial condition, results of operations or cash
flows.
On May 1,
2009, RRI completed the previously announced sale of its Texas retail business
to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection
with the sale, RRI changed its name to RRI Energy, Inc. The sale does
not alter RRI’s contractual obligations to indemnify CenterPoint Energy and its
subsidiaries for certain liabilities, including their indemnification regarding
certain litigation, nor does it affect the terms of existing guaranty
arrangements for certain RRI gas transportation contracts.
Natural Gas Measurement
Lawsuits. CERC Corp. and certain of its subsidiaries 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.
Following dismissal of the plaintiff's motion to the Tenth Circuit for
rehearing, the plaintiff sought review by the United States Supreme Court, but
his petition for certiorari was denied in October 2009.
In
addition, CERC Corp. and certain of its subsidiaries are defendants in two
mismeasurement lawsuits brought against approximately 245 pipeline companies and
their affiliates pending in state court in Stevens County, Kansas. In
one case (originally filed in May 1999 and amended four times), the plaintiffs
purport to represent a class of royalty owners who allege that the defendants
have engaged in systematic mismeasurement of the volume of natural gas for more
than 25 years. The plaintiffs amended their petition in this suit in July 2003
in response to an order from the judge denying certification of the plaintiffs’
alleged class. In the amendment the plaintiffs dismissed their claims against
certain defendants (including two CERC Corp. subsidiaries), limited the scope of
the class of plaintiffs they purport to represent and eliminated previously
asserted claims based on mismeasurement of the British thermal unit (Btu)
content of the gas. The same plaintiffs then filed a second lawsuit, again as
representatives of a putative class of royalty owners, in which they assert
their claims that the defendants have engaged in systematic mismeasurement of
the Btu content of natural gas for more than 25 years. In both lawsuits, the
plaintiffs seek compensatory damages, along with statutory penalties, treble
damages, interest, costs and fees. In September 2009, the district
court in Stevens County, Kansas, denied plaintiffs' request for class
certification of their case, but the plaintiffs have sought rehearing of that
dismissal.
CERC
believes that there has been no systematic mismeasurement of gas and that these
lawsuits are without merit. CERC 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 2004, a lawsuit was filed by certain CERC ratepayers in Texas
and Arkansas in circuit court in Miller County, Arkansas against CERC Corp.,
CenterPoint Energy, Entex Gas Marketing Company (EGMC), CenterPoint Energy Gas
Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS),
CenterPoint Energy Pipeline Services, Inc. (CEPS), Mississippi River
Transmission Corp. (MRT) and various non-affiliated companies alleging fraud,
unjust enrichment and civil conspiracy with respect to rates charged to certain
consumers of natural gas in Arkansas, Louisiana, Minnesota, Mississippi,
Oklahoma and Texas. Subsequently, the plaintiffs dropped CEGT and MRT as
defendants. Although the plaintiffs in the Miller County case sought class
certification, no class was certified. In June 2007, the Arkansas Supreme Court
determined that the Arkansas claims were within the sole and exclusive
jurisdiction of the Arkansas Public Service Commission (APSC). In response to
that ruling, in August 2007 the Miller County court stayed but refused to
dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court
directed the Miller County court to dismiss the entire case for lack of
jurisdiction. The Miller County court subsequently dismissed the case in
accordance with the Arkansas Supreme Court’s mandate and all appellate deadlines
have expired.
In June
2007, CenterPoint Energy, CERC Corp., 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 CenterPoint Energy,
CERC Corp., 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. All appellate deadlines expired without an appeal of the
final declaratory judgment.
In August
2007, the Arkansas plaintiff in the Miller County litigation initiated a
complaint at the APSC seeking a decision concerning the extent of the APSC’s
jurisdiction over the Miller County case and an investigation into the merits of
the allegations asserted in his complaint with respect to CERC. In February
2009, the Arkansas plaintiff notified the APSC that he would no longer pursue
his claims, and in July 2009 the complaint proceeding was dismissed by the
APSC. All appellate deadlines expired without an appeal of the
dismissal order.
Environmental
Matters
Manufactured Gas Plant Sites.
CERC and its predecessors operated manufactured gas plants (MGPs) in the past.
In Minnesota, CERC has completed remediation on two sites, other than ongoing
monitoring and water treatment. There are five remaining sites in CERC’s
Minnesota service territory. CERC believes that it has no liability with respect
to two of these sites.
At
September 30, 2009, CERC had accrued $14 million for remediation of
these Minnesota sites and the estimated range of possible remediation costs for
these sites was $4 million to $35 million based on remediation
continuing for 30 to 50 years. The cost estimates are based on studies of a site
or industry average costs for remediation of sites of similar size. The actual
remediation costs will be dependent upon the number of sites to be remediated,
the participation of other potentially responsible parties (PRP), if any, and
the remediation methods used. CERC has utilized an environmental expense tracker
mechanism in its rates in Minnesota to recover estimated costs in excess of
insurance recovery. As of September 30, 2009, CERC 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 CERC or may have been owned by one of its former affiliates. CERC
has been named as a defendant in a lawsuit filed in the United States District
Court, District of Maine, under which contribution is sought by private parties
for the cost to remediate former MGP sites based on the previous ownership of
such sites by former affiliates of CERC or its divisions. CERC has also been
identified as a PRP by the State of Maine for a site that is the subject of the
lawsuit. In June 2006, the federal district court in Maine ruled that the
current owner of the site is responsible for site remediation but that an
additional evidentiary hearing is required to determine if other potentially
responsible parties, including CERC, would have to contribute to that
remediation. CERC 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. In September 2009,
the federal district court granted CERC’s motion for summary judgment in the
proceeding. Although it is likely that the plaintiff will pursue an
appeal from that dismissal, further action will not be taken until the district
court disposes of claims against other defendants in the case. CERC does not
expect the ultimate outcome to have a material impact on its financial
condition, results of operations or cash flows.
Mercury Contamination. CERC’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. CERC has found this type of contamination at some
sites in the past, and CERC 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 CERC’s experience and that of others in the natural
gas industry to date and on the current regulations regarding remediation of
these sites, CERC 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 CERC’s predecessors have contained asbestos
insulation and other asbestos-containing materials. CERC 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. CERC anticipates that
additional claims like those received may be asserted in the
future. Although their ultimate outcome cannot be predicted at this
time, CERC 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 its financial condition, results of operations or cash
flows.
Groundwater Contamination
Litigation. Predecessor entities of CERC, along with several other
entities, are defendants in litigation, St. Michel Plantation, LLC, et al,
v. White, et al., pending in civil district court in Orleans Parish,
Louisiana. In the lawsuit, the plaintiffs allege that their property in
Terrebonne Parish, Louisiana suffered salt water contamination as a result of
oil and gas drilling activities conducted by the defendants. Although a
predecessor of CERC held an interest in two oil and gas leases on a portion of
the property at issue, neither it nor any other CERC entities drilled or
conducted other oil and gas operations on those leases. In January 2009,
CERC
and the
plaintiffs reached agreement on the terms of a settlement that, if ultimately
approved by the Louisiana Department of Natural Resources, is expected to
resolve this litigation. CERC 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 CERC 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, CERC 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, CERC does not expect,
based on its experience to date, these matters, either individually or in the
aggregate, to have a material adverse effect on its financial condition, results
of operations or cash flows.
Other
Proceedings
CERC 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. CERC regularly analyzes current information and, as
necessary, provides accruals for probable liabilities on the eventual
disposition of these matters. CERC does not expect the disposition of these
matters to have a material adverse effect on its financial condition, results of
operations or cash flows.
(d)
Guaranties
Prior to
CenterPoint Energy’s distribution of its ownership in RRI to its shareholders,
CERC had guaranteed certain contractual obligations of what became RRI’s trading
subsidiary. When the companies separated, RRI agreed to secure CERC
against obligations under the guaranties RRI had been unable to extinguish by
the time of separation. Pursuant to such agreement, as amended in December
2007, RRI has agreed to provide to CERC cash or letters of credit
as security against CERC’s obligations under its remaining guaranties for
demand charges under certain gas purchase and transportation agreements if and
to the extent changes in market conditions expose CERC to a risk of loss on
those guaranties. As of September 30, 2009, RRI was not required to
provide security to CERC. If RRI should fail to perform the contractual
obligations, CERC could have to honor its guarantee and, in such event,
collateral provided as security may be insufficient to satisfy CERC’s
obligations.
During
the three months and nine months ended September 30, 2008, the effective
tax rate was 36% and 38%, respectively. During the three months and
nine months ended September 30, 2009, the effective tax rate was 49% and
39%, respectively. Lower pre-tax income in 2009 primarily affected
the comparability of the effective tax rate for the three months ended
September 30, 2008 and 2009.
The
following table summarizes CERC’s uncertain tax positions at December 31,
2008 and September 30, 2009:
|
|
December
31,
2008
|
|
|
September 30,
2009
|
|
|
|
(in
millions)
|
|
Liability
(receivable) for uncertain tax positions
|
|
$ |
(12 |
) |
|
$ |
8 |
|
Portion
of receivable for uncertain tax positions that, if
recognized,
would reduce the effective income tax rate
|
|
|
1 |
|
|
|
- |
|
Interest
accrued on uncertain tax positions
|
|
|
(4 |
) |
|
|
(5 |
) |
(13)
|
Estimated
Fair Value of Financial Instruments
|
The fair
values of cash and cash equivalents, investments in debt and equity securities
classified as "available-for-sale" and "trading" and short-term borrowings are
estimated to be approximately equivalent to carrying amounts and have been
excluded from the table below. The fair values of non-trading derivative assets
and liabilities are equivalent to their carrying amounts in the Condensed
Consolidated Balance Sheets at December 31, 2008 and September 30, 2009 and
have been determined using quoted market prices for the same or similar
instruments when available or other estimation techniques (see Notes 5 and 6).
Therefore, these financial instruments are stated at fair value and are excluded
from the table below. The fair value of each debt instrument is
determined by multiplying the principal amount of each debt instrument by the
market price.
|
|
December
31, 2008
|
|
September 30,
2009
|
|
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
|
|
|
(In
millions)
|
|
Financial
liabilities:
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
$ |
3,719 |
|
$ |
3,568 |
|
$ |
2,812 |
|
$ |
2,939 |
|
(14)
|
Reportable
Business Segments
|
Because
CERC is an indirect wholly owned subsidiary of CenterPoint Energy, CERC’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. CERC uses operating income as the measure of
profit or loss for its business segments.
CERC’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 CERC’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 September 30, 2008
|
|
|
|
Revenues
from
External
Customers
|
|
Net
Intersegment
Revenues
|
|
Operating
Income
(Loss)
|
|
Natural
Gas Distribution
|
|
$ |
548 |
|
$ |
2 |
|
$ |
(6 |
) |
Competitive
Natural Gas Sales and Services
|
|
|
1,256 |
|
|
13 |
|
|
35 |
|
Interstate
Pipelines
|
|
|
96 |
|
|
47 |
|
|
55 |
(1) |
Field
Services
|
|
|
60 |
|
|
11 |
|
|
44 |
|
Other
Operations
|
|
|
— |
|
|
— |
|
|
1 |
|
Eliminations
|
|
|
— |
|
|
(73 |
) |
|
— |
|
Consolidated
|
|
$ |
1,960 |
|
$ |
— |
|
$ |
129 |
|
|
|
For
the Three Months Ended September 30, 2009
|
|
|
|
Revenues
from
External
Customers
|
|
|
Net
Intersegment
Revenues
|
|
Operating
Income
(Loss)
|
|
Natural
Gas Distribution
|
|
$ |
400 |
|
|
$ |
2 |
|
$ |
(15 |
) |
Competitive
Natural Gas Sales and Services
|
|
|
395 |
|
|
|
4 |
|
|
(8 |
) |
Interstate
Pipelines
|
|
|
119 |
|
|
|
34 |
|
|
64 |
|
Field
Services
|
|
|
51 |
|
|
|
12 |
|
|
23 |
|
Other
Operations
|
|
|
— |
|
|
|
— |
|
|
— |
|
Eliminations
|
|
|
— |
|
|
|
(52 |
) |
|
— |
|
Consolidated
|
|
$ |
965 |
|
|
$ |
— |
|
$ |
64 |
|
|
|
For
the Nine Months Ended September 30, 2008
|
|
|
|
|
|
|
Revenues
from
External
Customers
|
|
|
Net
Intersegment
Revenues
|
|
|
Operating
Income
(Loss)
|
|
|
Total
Assets
as
of December 31,
2008
|
|
Natural
Gas Distribution
|
|
$ |
2,969 |
|
|
$ |
7 |
|
|
$ |
119 |
|
|
$ |
4,961 |
|
Competitive
Natural Gas Sales and Services
|
|
|
3,599 |
|
|
|
33 |
|
|
|
36 |
|
|
|
1,315 |
|
Interstate
Pipelines
|
|
|
337 |
|
|
|
131 |
|
|
|
227 |
(1) |
|
|
3,578 |
|
Field
Services
|
|
|
164 |
|
|
|
27 |
|
|
|
121 |
(2) |
|
|
826 |
|
Other
Operations
|
|
|
— |
|
|
|
— |
|
|
|
(2 |
) |
|
|
724 |
|
Eliminations
|
|
|
— |
|
|
|
(198 |
) |
|
|
— |
|
|
|
(1,193 |
) |
Consolidated
|
|
$ |
7,069 |
|
|
$ |
— |
|
|
$ |
501 |
|
|
$ |
10,211 |
|
|
|
For
the Nine Months Ended September 30, 2009
|
|
|
|
|
|
|
Revenues
from
External
Customers
|
|
|
Net
Intersegment
Revenues
|
|
|
Operating
Income
(Loss)
|
|
|
Total
Assets
as
of September 30,
2009
|
|
Natural
Gas Distribution
|
|
$ |
2,334 |
|
|
$ |
7 |
|
|
$ |
105 |
|
|
$ |
4,281 |
|
Competitive
Natural Gas Sales and Services
|
|
|
1,585 |
|
|
|
11 |
|
|
|
— |
|
|
|
1,065 |
|
Interstate
Pipelines
|
|
|
355 |
|
|
|
106 |
|
|
|
194 |
|
|
|
3,478 |
|
Field
Services
|
|
|
158 |
|
|
|
18 |
|
|
|
72 |
|
|
|
934 |
|
Other
Operations
|
|
|
— |
|
|
|
— |
|
|
|
(4 |
) |
|
|
404 |
|
Eliminations
|
|
|
— |
|
|
|
(142 |
) |
|
|
— |
|
|
|
(909 |
) |
Consolidated
|
|
$ |
4,432 |
|
|
$ |
— |
|
|
$ |
367 |
|
|
$ |
9,253 |
|
|
(1)
|
Included
in operating income of Interstate Pipelines for the three and nine months
ended September 30, 2008 is a $7 million loss on pipeline assets
removed from service. Also included in operating income of
Interstate Pipelines for the nine months ended September 30, 2008 is
an $18 million gain on the sale of two storage development
projects.
|
|
(2)
|
Included
in operating income of Field Services for the nine months ended
September 30, 2008 is an $11 million gain related to a
settlement and contract buyout of one of its customers and a
$6 million gain on the sale of
assets.
|
(15)
|
Other
Currents Assets and Liabilities
|
Included
in other current assets on the Condensed Consolidated Balance Sheets at
December 31, 2008 and September 30, 2009 was $128 million and
$81 million, respectively of under-recovered gas cost. Included in other
current liabilities on the Condensed Consolidated Balance Sheets at
December 31, 2008 and September 30, 2009 was $79 million and
$21 million, respectively, of over recovered gas cost.
CERC has
evaluated all subsequent events through the date these Interim Condensed
Financial Statements were issued, which was November 10, 2009.
Item
2.
MANAGEMENT’S NARRATIVE ANALYSIS OF THE 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 and nine months ended September 30, 2008 and the three and nine
months ended September 30, 2009. Reference is made to “Management’s
Narrative Analysis of Results of Operations” in Item 7 of our 2008 Form
10-K.
EXECUTIVE
SUMMARY
Recent
Events
Long-Term
Gas Gathering and Treatment Agreements
In
September 2009, CenterPoint Energy Field Services, Inc. (CEFS), our wholly-owned
natural gas gathering and treating subsidiary, entered into long-term agreements
with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an
indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide
gathering and treating services for their natural gas production from the
Haynesville Shale and Bossier Shale formations in Texas and Louisiana. CEFS has
also acquired existing jointly-owned gathering facilities from EnCana and Shell
in De Soto and Red River parishes in northwest Louisiana.
Under the
terms of the agreements, CEFS commenced gathering and treating services
immediately utilizing the acquired facilities. CEFS will also expand the
acquired facilities to gather and treat up to 700 million cubic feet (MMcf)
per day of natural gas from their current throughput of over 100 MMcf per day.
If EnCana or Shell elect, CEFS will further expand the facilities in order to
gather and treat additional future volumes.
New
construction to reach capacity of 700 MMcf per day includes more than 200 miles
of pipelines, nearly 25,500 horsepower of compression and over 800 MMcf per day
of treating capacity.
Each of
the agreements includes volume commitments for which CEFS has exclusive rights
to gather Shell’s and EnCana’s natural gas production.
CEFS
estimates that the purchase of existing facilities and construction to gather
700 MMcf per day will cost up to $325 million. If EnCana and Shell elect
expansion of the project to gather and process additional future volumes of up
to 1 billion cubic feet per day (Bcf), CEFS estimates that the expansion would
cost as much as an additional $300 million and EnCana and Shell would
provide incremental volume commitments. Funds for construction will be provided
from anticipated cash flows from operations, lines of credit or proceeds from
the sale of debt or equity securities.
Debt
Transactions
On August
13, 2009, Southeast Supply Header, LLC (SESH) issued $375 million of 4.85%
senior notes due 2014. SESH used one-half of the proceeds of the
notes to repay a construction loan to us in the amount of
$186 million. We used the proceeds from the construction loan
repayment to repay borrowings under CERC Corp.’s credit facility.
On
October 7, 2009, the size of CERC Corp.’s revolving credit facility was reduced
from $950 million to $915 million through removal of Lehman Brothers
Bank, FSB (Lehman) as a lender. Prior to its removal, Lehman had a
$35 million commitment to lend. All credit facility loans to
CERC Corp. that were funded by Lehman were repaid in September
2009.
On
October 9, 2009, we amended our receivables facility to extend the termination
date to October 8, 2010. Availability under our 364-day receivables
facility ranges from $150 million to $375 million, reflecting seasonal
changes in receivables balances.
Asset
Management Agreements
Our
natural gas distribution businesses (Gas Operations) entered into various asset
management agreements associated with its utility distribution service in
Arkansas, Oklahoma, Louisiana, Mississippi and Texas. Generally, an asset
management agreement is a contract between an asset holder and an asset manager
that strives to maximize the revenue-earning potential of the asset. In these
agreements, Gas Operations agreed to release transportation and storage capacity
to another party to manage gas storage, supply and delivery arrangements for Gas
Operations when the released capacity is not needed and thereby maximize the
value of the assets. Gas Operations will be compensated by the asset manager, in
part based on the results of the asset optimization, and entering into the asset
management agreements will reduce working capital requirements. The
agreements are expected, subject to regulatory approval, to commence in the
fourth quarter of 2009 and to continue for various terms extending up to
2016.
Gas
Operations has filed applications with state regulatory commissions in Arkansas,
Louisiana, Mississippi and Oklahoma for approval of the applicable asset
management agreements and to retain a share of the proceeds, with the remainder
to benefit customers. Commission approval has been obtained in Louisiana,
Oklahoma, Mississippi and for one of two agreements in Arkansas. A filing
is expected to be made in Texas in the fourth quarter of 2009.
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 II of this Form
10-Q.
The
following table sets forth our consolidated results of operations for the three
and nine months ended September 30, 2008 and 2009, followed by a discussion
of our consolidated results of operations.
|
|
Three
Months Ended
September 30,
|
|
|
Nine
Months Ended
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
|
(in
millions)
|
|
Revenues
|
|
$ |
1,960 |
|
|
$ |
965 |
|
|
$ |
7,069 |
|
|
$ |
4,432 |
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
|
1,532 |
|
|
|
582 |
|
|
|
5,675 |
|
|
|
3,081 |
|
Operation
and maintenance
|
|
|
212 |
|
|
|
230 |
|
|
|
601 |
|
|
|
686 |
|
Depreciation
and amortization
|
|
|
54 |
|
|
|
58 |
|
|
|
163 |
|
|
|
172 |
|
Taxes
other than income taxes
|
|
|
33 |
|
|
|
31 |
|
|
|
129 |
|
|
|
126 |
|
Total
Expenses
|
|
|
1,831 |
|
|
|
901 |
|
|
|
6,568 |
|
|
|
4,065 |
|
Operating
Income
|
|
|
129 |
|
|
|
64 |
|
|
|
501 |
|
|
|
367 |
|
Interest
and Other Finance Charges
|
|
|
(51 |
) |
|
|
(52 |
) |
|
|
(148 |
) |
|
|
(159 |
) |
Equity
in earnings of unconsolidated affiliates
|
|
|
23 |
|
|
|
(3 |
) |
|
|
46 |
|
|
|
8 |
|
Other
Income, net
|
|
|
3 |
|
|
|
1 |
|
|
|
7 |
|
|
|
4 |
|
Income
Before Income Taxes
|
|
|
104 |
|
|
|
10 |
|
|
|
406 |
|
|
|
220 |
|
Income
Tax Expense
|
|
|
(37 |
) |
|
|
(5 |
) |
|
|
(153 |
) |
|
|
(86 |
) |
Net
Income
|
|
$ |
67 |
|
|
$ |
5 |
|
|
$ |
253 |
|
|
$ |
134 |
|
Three
months ended September 30, 2009 compared to three months ended
September 30, 2008
We
reported net income of $5 million for the three months ended
September 30, 2009 compared to $67 million for the same period in
2008. The decrease in net income of $62 million was primarily
due to a $65 million decrease
in
operating income from our business segments as discussed below and a
$26 million decrease in equity in earnings of unconsolidated affiliates,
partially offset by a $32 million decrease in income tax
expense.
Nine
months ended September 30, 2009 compared to nine months ended
September 30, 2008
We
reported net income of $134 million for the nine months ended
September 30, 2009 compared to $253 million for the same period in
2008. The decrease in net income of $119 million was primarily
due to a $134 million decrease in operating income from our business
segments as discussed below, a $38 million decrease in equity in earnings
of unconsolidated affiliates and an $11 million increase in interest and
other finance charges, partially offset by a $67 million decrease in income
tax expense.
Income Tax Expense. During the three months
and nine months ended September 30, 2008, the effective tax rate was 36%
and 38%, respectively. During the three months and nine months ended
September 30, 2009, the effective tax rate was 49% and 39%,
respectively. Lower pre-tax income in 2009 primarily affected the
comparability of the effective tax rate for the three months ended
September 30, 2008 and 2009.
RESULTS
OF OPERATIONS BY BUSINESS SEGMENT
The
following table presents operating income (loss) for each of our business
segments for the three and nine months ended September 30, 2008 and 2009
(in millions), 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
September 30,
|
|
Nine
Months Ended
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
2008
|
|
|
2009
|
|
Natural
Gas Distribution
|
|
$ |
(6 |
) |
|
$ |
(15 |
) |
|
$ |
119 |
|
|
$ |
105 |
|
Competitive
Natural Gas Sales and Services
|
|
|
35 |
|
|
|
(8 |
) |
|
|
36 |
|
|
|
— |
|
Interstate
Pipelines
|
|
|
55 |
|
|
|
64 |
|
|
|
227 |
|
|
|
194 |
|
Field
Services
|
|
|
44 |
|
|
|
23 |
|
|
|
121 |
|
|
|
72 |
|
Other
Operations
|
|
|
1 |
|
|
|
— |
|
|
|
(2 |
) |
|
|
(4 |
) |
Total
Consolidated Operating Income
|
|
$ |
129 |
|
|
$ |
64 |
|
|
$ |
501 |
|
|
$ |
367 |
|
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 Businesses," "─ Risk Factors Associated
with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A
of Part II of this Form 10-Q.
The
following table provides summary data of our Natural Gas Distribution business
segment for the three and nine months ended September 30, 2008 and 2009 (in
millions, except throughput and customer data):
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
Revenues
|
|
$ |
550 |
|
|
$ |
402 |
|
|
$ |
2,976 |
|
|
$ |
2,341 |
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
|
351 |
|
|
|
198 |
|
|
|
2,196 |
|
|
|
1,538 |
|
Operation
and maintenance
|
|
|
139 |
|
|
|
157 |
|
|
|
436 |
|
|
|
478 |
|
Depreciation
and amortization
|
|
|
40 |
|
|
|
40 |
|
|
|
118 |
|
|
|
121 |
|
Taxes
other than income taxes
|
|
|
26 |
|
|
|
22 |
|
|
|
107 |
|
|
|
99 |
|
Total
expenses
|
|
|
556 |
|
|
|
417 |
|
|
|
2,857 |
|
|
|
2,236 |
|
Operating
Income (Loss)
|
|
$ |
(6 |
) |
|
$ |
(15 |
) |
|
$ |
119 |
|
|
$ |
105 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(in Bcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
13 |
|
|
|
13 |
|
|
|
117 |
|
|
|
111 |
|
Commercial
and industrial
|
|
|
41 |
|
|
|
38 |
|
|
|
171 |
|
|
|
154 |
|
Total
Throughput
|
|
|
54 |
|
|
|
51 |
|
|
|
288 |
|
|
|
265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of customers at period end:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
2,936,777 |
|
|
|
2,954,095 |
|
|
|
2,936,777 |
|
|
|
2,954,095 |
|
Commercial
and industrial
|
|
|
244,959 |
|
|
|
241,036 |
|
|
|
244,959 |
|
|
|
241,036 |
|
Total
|
|
|
3,181,736 |
|
|
|
3,195,131 |
|
|
|
3,181,736 |
|
|
|
3,195,131 |
|
Three
months ended September 30, 2009 compared to three months ended
September 30, 2008
Our
Natural Gas Distribution business segment reported an operating loss of
$15 million for the three months ended September 30, 2009 compared to
an operating loss of $6 million for the three months ended
September 30, 2008. Operating margin (revenues less cost of gas) increased
$5 million primarily due to increased rates ($4 million). Operation
and maintenance expenses increased $18 million primarily due to increased
pension expense ($8 million), higher labor and non-pension related benefits
expense ($4 million), customer related expenses and support services costs
($5 million) and increases in other expenses ($4 million), partially
offset by lower bad debt expense ($4 million). Taxes other than
income taxes decreased primarily due to lower gross receipts taxes.
Nine
months ended September 30, 2009 compared to nine months ended
September 30, 2008
Our
Natural Gas Distribution business segment reported operating income of
$105 million for the nine months ended September 30, 2009 compared to
operating income of $119 million for the nine months ended
September 30, 2008. Operating margin improved $23 million
primarily as a result of rate increases ($18 million), recovery of higher
energy-efficiency costs ($4 million), increased non-utility revenues
($5 million), residential customer growth ($2 million), with the
addition of approximately 17,000 customers, and increased margin from commercial
and industrial customers ($2 million), partially offset by decreased gross
receipts taxes ($10 million). Operation and maintenance expenses
increased $42 million primarily due to increased pension expense
($26 million), higher labor and non-pension related benefits expense
($11 million) and increased customer-related expenses and support services
costs ($11 million), partially offset by lower bad debt expense
($8 million) and other expense reductions
($3 million). Depreciation expense increased due to higher plant
balances. Taxes other than income taxes decreased due to the gross
receipts taxes above, partially offset by an increase in property taxes
($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 Businesses," "─ Risk Factors Associated
with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A
of Part II of this Form 10-Q.
The
following table provides summary data of our Competitive Natural Gas Sales and
Services business segment for the three and nine months ended September 30,
2008 and 2009 (in millions, except throughput and customer data):
|
|
Three
Months Ended
September 30,
|
|
|
Nine
Months Ended
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
Revenues
|
|
$ |
1,269 |
|
|
$ |
399 |
|
|
$ |
3,632 |
|
|
$ |
1,596 |
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
|
1,225 |
|
|
|
396 |
|
|
|
3,567 |
|
|
|
1,562 |
|
Operation
and maintenance
|
|
|
8 |
|
|
|
10 |
|
|
|
26 |
|
|
|
30 |
|
Depreciation
and amortization
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
Taxes
other than income taxes
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
Total
expenses
|
|
|
1,234 |
|
|
|
407 |
|
|
|
3,596 |
|
|
|
1,596 |
|
Operating
Income (Loss)
|
|
$ |
35 |
|
|
$ |
(8 |
) |
|
$ |
36 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(in Bcf)
|
|
|
125 |
|
|
|
115 |
|
|
|
392 |
|
|
|
370 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of customers at period end
|
|
|
8,988 |
|
|
|
10,934 |
|
|
|
8,988 |
|
|
|
10,934 |
|
Three
months ended September 30, 2009 compared to three months ended
September 30, 2008
Our
Competitive Natural Gas Sales and Services business segment reported an
operating loss of $8 million for the three months ended September 30,
2009 compared to operating income of $35 million for the three months ended
September 30, 2008. The decrease in operating income of
$43 million was primarily due to the unfavorable impact of mark-to-market
accounting for non-trading financial derivatives for the third quarter of 2009
of $6 million versus a favorable impact of $46 million for the same
period in 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 derivative contracts create the mark-to-market accounting
adjustment. This decrease was partially offset by the absence of a
write-down of natural gas inventory to the lower of cost or market in the
current quarter as compared to a $24 million write-down in the third
quarter 2008. The remaining $15 million decrease was comprised of reduced
margin of $12 million, due to lower sales volume and reduced locational
spreads and increased operating expense of $3 million.
Nine
months ended September 30, 2009 compared to nine months ended
September 30, 2008
Our
Competitive Natural Gas Sales and Services business segment reported operating
income of $-0- for the nine months ended September 30, 2009 compared to
operating income of $36 million for the nine months ended
September 30, 2008. The decrease in operating income of
$36 million was primarily due to the unfavorable impact of the
mark-to-market valuation for non-trading financial derivatives for the first
nine months of 2009 of $22 million versus a favorable impact of
$14 million for the same period in 2008. This decrease in
operating income was partially offset by a $6 million write-down of natural
gas inventory to the lower of cost or market for the nine months ended
September 30, 2009 compared to a $24 million write-down in the same
period last year. The remaining $18 million decrease was comprised of
reduced margin of $13 million and increased operating expense of
$5 million for the nine months ended September 30, 2009 compared to
the same period last year.
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 Businesses," "─ Risk Factors Associated
with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A
of Part II of this Form 10-Q.
The
following table provides summary data of our Interstate Pipelines business
segment for the three and nine months ended September 30, 2008 and 2009 (in
millions, except throughput data):
|
|
Three
Months Ended
September 30,
|
|
|
Nine
Months Ended
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
Revenues
|
|
$ |
143 |
|
|
$ |
153 |
|
|
$ |
468 |
|
|
$ |
461 |
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
|
24 |
|
|
|
22 |
|
|
|
97 |
|
|
|
85 |
|
Operation
and maintenance
|
|
|
47 |
|
|
|
47 |
|
|
|
93 |
|
|
|
123 |
|
Depreciation
and amortization
|
|
|
11 |
|
|
|
12 |
|
|
|
34 |
|
|
|
36 |
|
Taxes
other than income taxes
|
|
|
6 |
|
|
|
8 |
|
|
|
17 |
|
|
|
23 |
|
Total
expenses
|
|
|
88 |
|
|
|
89 |
|
|
|
241 |
|
|
|
267 |
|
Operating
Income
|
|
$ |
55 |
|
|
$ |
64 |
|
|
$ |
227 |
|
|
$ |
194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
throughput (in Bcf) :
|
|
|
360 |
|
|
|
378 |
|
|
|
1,145 |
|
|
|
1,235 |
|
Three
months ended September 30, 2009 compared to three months ended
September 30, 2008
Our
Interstate Pipeline business segment reported operating income of
$64 million for the three months ended September 30, 2009 compared to
$55 million for the three months ended September 30,
2008. Margins (revenues less natural gas costs) increased
$12 million primarily due to a new backhaul agreement on the Carthage to
Perryville pipeline ($10 million) and new contracts with power generation
customers ($6 million). These increases were partially offset by
reduced other transportation margins and ancillary services ($4 million)
primarily due to the decline in commodity prices from the significantly higher
levels in 2008. Operations and maintenance expenses increased due to
costs associated with incremental facilities and increased pension expenses
($7 million), but that increase was offset by a write-down associated with
pipeline assets removed from service in the third quarter of 2008
($7 million). Depreciation and amortization expenses increased
$1 million and taxes other than income increased by $2 million,
$1 million of which was due to 2008 tax refunds.
Equity
Earnings. In addition, this business segment recorded equity
income of $18 million and equity loss of $5 million for the three
months ended September 30, 2008 and 2009, respectively, from its
50 percent interest in SESH, a jointly-owned pipeline that went into
service in September 2008. Approximately $17 million of income in the
third quarter of 2008 was pre-operating allowance for funds used during
construction in 2008. The third quarter 2009 loss of $5 million
included a non-cash pre-tax charge of $11 million associated with the
write-off of certain regulatory assets resulting from SESH’s decision to
discontinue the use of guidance for accounting for regulated operations. The
charge more than offset the equity income from SESH’s ongoing operations of
$6 million for the third quarter of 2009. These amounts are
included in Equity in Earnings of Unconsolidated Affiliates under the Other
Income (Expense) caption.
Nine
months ended September 30, 2009 compared to nine months ended
September 30, 2008
Our
Interstate Pipeline business segment reported operating income of
$194 million for the nine months ended September 30, 2009 compared to
$227 million for the nine months ended September 30, 2008. Margins
(revenues less natural gas costs) increased $5 million primarily due to the
Carthage to Perryville pipeline ($22 million) and new contracts with power
generation customers ($15 million). These increases were
partially offset by reduced other transportation margins and ancillary services
($32 million) primarily due to the decline in commodity prices from the
significantly higher levels in 2008. Operations and maintenance
expenses increased primarily due to a gain on the sale of two storage
development projects in 2008 ($18 million) and costs associated with
incremental facilities and increased pension expenses
($19 million). These expenses were partially offset by a
write-down associated with pipeline assets removed from service in the third
quarter of 2008 ($7 million). Depreciation and amortization
expenses increased $2 million and taxes other than income increased by
$6 million, $3 million of which was due to 2008 tax
refunds.
Equity
Earnings. In addition, this business segment recorded equity
income of $34 million and $2 million for the nine months ended
September 30, 2008 and 2009, respectively, from its 50 percent
interest in SESH. Approximately $33 million of the income in the nine
months ended September 30, 2008 was pre-operating allowance for funds used
during construction in 2008. The 2009 results include a non-cash pre-tax
charge of
$16 million
to reflect SESH’s decision to discontinue the use of guidance for accounting for
regulated operations and the receipt of a one-time payment related to the
construction of the pipeline and a reduction in estimated property taxes, of
which our 50 percent share was $5 million. 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 Businesses," "─ Risk Factors Associated
with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A
of Part II of this Form 10-Q.
The
following table provides summary data of our Field Services business segment for
the three and nine months ended September 30, 2008 and 2009 (in millions,
except throughput data):
|
|
Three
Months Ended
September 30,
|
|
|
Nine
Months Ended
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
Revenues
|
|
$ |
71 |
|
|
$ |
63 |
|
|
$ |
191 |
|
|
$ |
176 |
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
|
5 |
|
|
|
18 |
|
|
|
11 |
|
|
|
36 |
|
Operation
and maintenance
|
|
|
19 |
|
|
|
17 |
|
|
|
48 |
|
|
|
54 |
|
Depreciation
and amortization
|
|
|
3 |
|
|
|
4 |
|
|
|
9 |
|
|
|
11 |
|
Taxes
other than income taxes
|
|
|
- |
|
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
Total
expenses
|
|
|
27 |
|
|
|
40 |
|
|
|
70 |
|
|
|
104 |
|
Operating
Income
|
|
$ |
44 |
|
|
$ |
23 |
|
|
$ |
121 |
|
|
$ |
72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering
throughput (in Bcf) :
|
|
|
109 |
|
|
|
106 |
|
|
|
311 |
|
|
|
312 |
|
Three
months ended September 30, 2009 compared to three months ended
September 30, 2008
Our Field
Services business segment reported operating income of $23 million for the
three months ended September 30, 2009 compared to $44 million for the
three months ended September 30, 2008. Operating income from new
projects and core gathering services increased approximately $4 million for
the three months ended September 30, 2009 when compared to the same period
in 2008 primarily due to continued development in the shale
plays. This increase was offset primarily by the effect of a decline
in commodity prices from the significantly higher levels in 2008 of
approximately $20 million. In addition, operating income decreased from the
prior year quarter associated with gains from system imbalances
($3 million).
Equity
Earnings. In addition, this business segment recorded equity
income of $4 million and $2 million in the three months ended
September 30, 2008 and 2009, respectively, from its 50 percent
interest in a jointly-owned gas processing plant. The decrease is driven by a
decrease in natural gas liquids prices. These amounts are included in
Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense)
caption.
Nine
months ended September 30, 2009 compared to nine months ended
September 30, 2008
Our Field
Services business segment reported operating income of $72 million for the
nine months ended September 30, 2009 compared to $121 million for the
nine months ended September 30, 2008. Operating income from new
projects and core gathering services increased approximately $16 million
for the nine months ended September 30, 2009 when compared to the same
period in 2008 primarily due to continued development in the shale
plays. This increase was offset primarily by the effect of a decline
in commodity prices of approximately $43 million from the significantly
higher prices experienced in 2008. Operating income for the nine months ended
September 30, 2009 also included higher costs associated with incremental
facilities and increased pension costs ($5 million). The nine month period
September 30, 2008 benefited from 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.
Equity
Earnings. In addition, this business segment recorded equity
income of $12 million and $6 million in the nine months ended
September 30, 2008 and 2009, respectively, from its 50 percent
interest in a jointly-owned gas
processing
plant. The decrease is driven by a decrease in natural gas liquids
prices. 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 II of this
Form 10-Q 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 cash requirements for the remaining three
months of 2009 are approximately $217 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 for the remaining three months of 2009. Cash needs or
discretionary financing or refinancing may also 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 RRI Energy, Inc. (RRI)
(formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) to its
shareholders, we had guaranteed certain contractual obligations of what became
RRI’s trading subsidiary. When the companies separated, RRI agreed to
secure us against obligations under the guaranties RRI had been unable to
extinguish by the time of separation. Pursuant to such agreement, as
amended in December 2007, RRI has agreed to provide to us cash or letters of
credit as security against our obligations under our remaining guaranties
for demand charges under certain gas purchase and transportation agreements if
and to the extent changes in market conditions expose us to a risk of loss on
those guaranties. As of September 30, 2009, RRI was not required to
provide security to us. If RRI should fail to perform the contractual
obligations, we could have to honor our guarantee and, in such event, collateral
provided as security may be insufficient to satisfy our
obligations.
Credit and Receivables
Facilities. On October 7, 2009, the size of CERC Corp.’s
revolving credit facility was reduced from $950 million to
$915 million through removal of Lehman as a lender. Prior to its
removal, Lehman had a $35 million commitment to lend. All credit
facility loans to CERC Corp. that were funded by Lehman were repaid in September
2009.
On
October 9, 2009, we amended our receivables facility to extend the termination
date to October 8, 2010. Availability under our 364-day receivables
facility ranges from $150 million to $375 million, reflecting seasonal
changes in receivables balances.
As of
October 19, 2009, we had the following facilities (in
millions):
Date
Executed
|
|
Type
of
Facility
|
|
Size
of
Facility
|
|
Amount
Utilized
at
October 19,
2009
|
|
Termination
Date
|
June
29, 2007
|
|
Revolver
|
|
$ |
915 |
|
$ |
30 |
|
June
29, 2012
|
October
9, 2009
|
|
Receivables
|
|
|
150 |
|
|
— |
|
October
8, 2010
|
CERC
Corp.’s $915 million credit facility’s first drawn cost is the London
Interbank Offered Rate (LIBOR) plus 45 basis points based on our current credit
ratings. The facility contains a debt to total capitalization
covenant. Under CERC Corp.’s 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 CERC
Corp.’s
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.
CERC
Corp.’s $915 million credit facility backstops a $915 million
commercial paper program under which we began issuing commercial paper in
February 2008. Our commercial paper is rated “P-3” by Moody’s Investors Service,
Inc. (Moody’s), “A-3” by Standard & Poor’s Rating Services, a division
of The McGraw Hill Companies (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.
Securities Registered with the
SEC. We have a shelf registration statement covering
$500 million principal amount of senior debt securities.
Temporary
Investments. As of October 19, 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 October 19, 2009, we had
borrowings of $272 million 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 October 19, 2009, Moody’s, S&P
and Fitch had assigned the following credit ratings to our senior unsecured
debt:
Moody’s
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S&P
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Fitch
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Rating
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Outlook(1)
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Rating
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Outlook(2)
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Rating
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Outlook(3)
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Baa3
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Stable
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BBB
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Negative
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BBB
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Stable
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__________
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(1)
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A
Moody’s rating outlook is an opinion regarding the likely direction of a
rating over the medium term.
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(2)
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An
S&P rating outlook assesses the potential direction of a long-term
credit rating over the intermediate to longer
term.
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(3)
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A
“stable” outlook from Fitch encompasses a one-to-two year horizon as to
the likely ratings direction.
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A decline
in credit ratings could increase borrowing costs under our $915 million
revolving credit facility. If our credit ratings had been downgraded one notch
by each of the three principal credit rating agencies from the ratings that
existed at September 30, 2009, the impact on the borrowing costs under our
bank credit facility would have been immaterial. A decline in credit
ratings would also increase the interest rate on long-term debt to be issued in
the capital markets and could negatively impact our ability to complete capital
market transactions. Additionally, a decline in credit ratings could increase
our cash collateral requirements and reduce our earnings.
We and
our subsidiaries purchase natural gas under supply agreements that contain an
aggregate credit threshold of $100 million based on CERC Corp.’s 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.
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
September 30, 2009, the amount posted as collateral aggregated
approximately $140 million ($94 million of which is associated with
price stabilization activities of our Natural Gas Distribution business
segment). Should the credit ratings of CERC Corp. (as the credit support
provider for CES) fall below certain levels, CES would be required to provide
additional collateral up to the amount of its previously unsecured credit limit.
We estimate that as of September 30, 2009, unsecured credit limits extended
to CES by counterparties aggregate $241 million; however, utilized credit
capacity was $73 million.
Pipeline
tariffs and contracts typically provide that if the credit ratings of a shipper
or the shipper’s guarantor drop below a threshold level, which is generally
investment grade ratings from both Moody’s and S&P, cash or other collateral
may be demanded from the shipper in an amount equal to the sum of three months’
charges for pipeline services plus the unrecouped cost of any lateral built for
such shipper. If the credit ratings of CERC Corp. decline below the applicable
threshold levels, we might need to provide cash or other collateral of as much
as $180 million as of September 30, 2009. The amount of
collateral will depend 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 September 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 Adversely
Affect Cash Requirements. In addition to the above factors,
our liquidity and capital resources could be adversely affected by:
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•
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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;
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•
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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;
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•
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increased
costs related to the acquisition of natural
gas;
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•
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increases
in interest expense in connection with debt refinancings and borrowings
under credit facilities;
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•
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various
regulatory actions;
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•
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increased
capital expenditures required for new gas pipeline or field services
projects;
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•
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the
ability of our customers to fulfill their payment obligations to
us;
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•
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the
ability of RRI and its subsidiaries to satisfy their obligations in
respect of RRI’s indemnity obligations to us and our subsidiaries or in
connection with the contractual obligations to a third party pursuant to
which we are their guarantor;
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•
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slower
customer payments and increased write-offs of receivables due to higher
gas prices or changing economic
conditions;
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•
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the
outcome of litigation brought by and against
us;
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•
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restoration
costs and revenue losses resulting from natural disasters such as
hurricanes and the timing of recovery of such restoration
costs; and
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•
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various
other risks identified in “Risk Factors” in Item 1A of Part II of this
Form 10-Q.
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Certain Contractual Limits on Our
Ability to Issue Securities and Borrow Money. CERC Corp.’s 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.
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 September 30, 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 September 30, 2009 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.
PART
II. OTHER INFORMATION
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.
The
following risk factors are provided to supplement and update the risk factors
contained in the reports we file with the SEC, including the risk factors
contained in Item 1A of Part I of our 2008 Form 10-K.
The
following information about risks, along with any additional legal proceedings
identified or referenced in Part II, Item 1 “Legal Proceedings” of this Form
10-Q and in “Legal Proceedings” in Item 3 of our 2008 Form 10-K, summarize the
principal risk factors associated with our businesses.
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
our natural gas distribution business (Gas Operations) are regulated by certain
municipalities and state commissions, and for our interstate pipelines by the
Federal Energy Regulatory Commission, 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 changes 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. An increase in natural gas prices would also increase our
working capital requirements by increasing the investment that must be made in
order to maintain natural gas inventory levels. Additionally, a
decrease in natural gas prices could increase the amount of collateral that we
must provide under our hedging arrangements.
A
decline in our credit rating could result in us having to provide collateral in
order to purchase gas or under our shipping or hedging
arrangements.
If our
credit rating were to decline, we might be required to post cash collateral in
order to purchase natural gas or under our shipping or hedging arrangements. If
a credit rating downgrade and the resultant cash collateral requirement were to
occur at a time when we were experiencing significant working capital
requirements or otherwise lacked liquidity, our results of operations, financial
condition and cash flows could be adversely affected.
The
revenues and results of operations of our interstate pipelines and field
services businesses are subject to fluctuations in the supply and price of
natural gas and natural gas liquids.
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, future pipeline, gathering and
treating systems 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 and gathering and
treating system projects in the future. The construction of new pipelines,
gathering and treating systems and related compression facilities may require
the expenditure of significant amounts of capital, which may exceed our
estimates. These projects may not be completed at the planned cost, on schedule
or at all. The construction of new pipeline, gathering, treating or compression
facilities is subject to construction cost overruns due to labor costs, costs of
equipment and materials such as steel and nickel, labor shortages or delays,
weather delays, inflation or other factors, which could be material. In
addition, the construction of these facilities is typically subject to the
receipt of approvals and permits from various regulatory agencies. Those
agencies may not approve the projects in a timely manner or may impose
restrictions or conditions on the projects that could potentially prevent a
project from proceeding, lengthen its expected completion schedule and/or
increase its anticipated cost. As a result, there is the risk that the new
facilities may not be able to achieve 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 Policy Act of 2005,
provided a comprehensive regulatory structure governing the organization,
capital structure, intracompany relationships and lines of business that could
be pursued by registered holding companies and their member companies. Following
repeal of that Act, some states in which we do business have sought to expand
their own regulatory frameworks to give their regulatory authorities increased
jurisdiction and scrutiny over similar aspects of the utilities that operate in
their states. Some of these frameworks attempt to regulate financing activities,
acquisitions and divestitures, and arrangements between the utilities and their
affiliates, and to restrict the level of non-utility businesses that can be
conducted within the holding company structure. Additionally they may impose
record keeping, record access, employee training and reporting requirements
related to affiliate transactions and reporting in the event of certain
downgrading of the utility’s bond rating.
These
regulatory frameworks could have adverse effects on our ability to operate our
utility operations, to finance our business and to provide cost-effective
utility service. In addition, if more than one state adopts restrictions over
similar activities, it may be difficult for us to comply with competing
regulatory requirements.
Risk
Factors Associated with Our Consolidated Financial Condition
If
we are unable to arrange future financings on acceptable terms, our ability to
refinance existing indebtedness could be limited.
As of
September 30, 2009, we had $3.1 billion of outstanding indebtedness on
a consolidated basis. As of September 30, 2009, approximately
$603 million principal amount of this debt is required to be paid through
2011 and an additional $239 million is money pool
borrowings. Our future financing activities may be significantly
affected by, among other things:
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general
economic and capital market
conditions;
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credit
availability from financial institutions and other
lenders;
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investor
confidence in us and the markets in which we
operate;
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maintenance
of acceptable credit ratings;
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market
expectations regarding our future earnings and cash
flows;
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market
perceptions of our and CenterPoint Energy's ability to access capital
markets on reasonable terms;
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our
exposure to RRI in connection with its indemnification obligations arising
in connection with its separation from us;
and
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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 2 of Part I of this Form 10-Q. 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 creditworthiness and liquidity of our parent company and our affiliates
could affect our creditworthiness and liquidity.
Our credit ratings and liquidity may be impacted by the creditworthiness and
liquidity of our affiliates. As of September 30, 2009, CenterPoint
Energy and its subsidiaries other than us have approximately $219 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. If CenterPoint Energy were to experience a
deterioration in its creditworthiness or liquidity, our creditworthiness and
liquidity could be adversely affected. In addition, from time to time
we and other affiliates invest or borrow funds in the money pool maintained by
CenterPoint Energy. If CenterPoint Energy or the affiliates that
borrow any funds that we might invest from time to time in the money pool were
to experience a deterioration in their creditworthiness or liquidity, our
creditworthiness, liquidity and the repayment of notes receivable from
CenterPoint Energy and our affiliates under the money pool could be adversely
impacted.
We
are an indirect wholly owned subsidiary of CenterPoint Energy. CenterPoint
Energy can exercise substantial control over our dividend policy and business
and operations and could do so in a manner that is adverse to our
interests.
We are
managed by officers and employees of CenterPoint Energy. Our management will
make determinations with respect to the following:
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our
payment of dividends;
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decisions
on our financings and our capital raising
activities;
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mergers
or other business combinations; and
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our
acquisition or disposition of
assets.
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There are
no contractual restrictions on our ability to pay dividends to CenterPoint
Energy. Our management could decide to increase our dividends to CenterPoint
Energy to support its cash needs. This could adversely affect our liquidity.
However, under our credit facility and our receivables facility, our ability to
pay dividends is restricted by a covenant that debt as a percentage of total
capitalization may not exceed 65%.
The
use of derivative contracts by us and our subsidiaries in the normal course of
business could result in financial losses that could negatively impact our
results of operations and those of our subsidiaries.
We and
our subsidiaries use derivative instruments, such as swaps, options, futures and
forwards, to manage our commodity, weather and financial market risks. We and
our subsidiaries could recognize financial losses as a result of volatility in
the market values of these contracts, or should a counterparty fail to perform.
In the absence of actively quoted market prices and pricing information from
external sources, the valuation of these financial instruments can involve
management’s judgment or use of estimates. As a result, changes in the
underlying assumptions or use of alternative valuation methods could affect the
reported fair value of these contracts.
We
derive a substantial portion of our operating income from subsidiaries through
which we hold a substantial portion of our assets.
We derive
a substantial portion of our operating income from, and hold a substantial
portion of our assets through, our subsidiaries. In general, these subsidiaries
are separate and distinct legal entities and have no obligation to provide us
with funds for our payment obligations, whether by dividends, distributions,
loans or otherwise. In addition, provisions of applicable law, such as those
limiting the legal sources of dividends, limit our subsidiaries’ ability to make
payments or other distributions to us, and our subsidiaries could agree to
contractual restrictions on their ability to make distributions.
Our right
to receive any assets of any subsidiary, and therefore the right of our
creditors to participate in those assets, will be effectively subordinated to
the claims of that subsidiary’s creditors, including trade creditors. In
addition, even if we were a creditor of any subsidiary, our rights as a creditor
would be subordinated to any security interest in the assets of that subsidiary
and any indebtedness of the subsidiary senior to that held by
us.
Risks
Common to Our Businesses and Other Risks
We
are subject to operational and financial risks and liabilities arising from
environmental laws and regulations.
Our
operations are subject to stringent and complex laws and regulations pertaining
to health, safety and the environment. As an owner or operator of natural gas
pipelines and distribution systems, and gas gathering and processing systems, we
must comply with these laws and regulations at the federal, state and local
levels. These laws and regulations can restrict or impact our business
activities in many ways, such as:
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restricting
the way we can handle or dispose of
wastes;
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limiting
or prohibiting construction activities in sensitive areas such as
wetlands, coastal regions, or areas inhabited by endangered
species;
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requiring
remedial action to mitigate pollution conditions caused by our operations,
or attributable to former operations;
and
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enjoining
the operations of facilities deemed in non-compliance with permits issued
pursuant to such environmental laws and
regulations.
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In order
to comply with these requirements, we may need to spend substantial amounts and
devote other resources from time to time to:
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construct
or acquire new equipment;
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acquire
permits for facility operations;
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modify
or replace existing and proposed equipment;
and
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clean
up or decommission waste disposal areas, fuel storage and management
facilities and other locations and
facilities.
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Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial actions, and the
issuance of orders enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to clean up and
restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.
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 RRI, RRI and its
subsidiaries assumed liabilities associated with various assets and businesses
Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the
applicable transferee subsidiaries to indemnify, CenterPoint Energy and its
subsidiaries, including us, with respect to liabilities associated with the
transferred assets and businesses. These indemnity provisions were intended to
place sole financial responsibility on RRI and its subsidiaries for all
liabilities associated with the current and historical businesses and operations
of RRI, regardless of the time those liabilities arose. If RRI were unable to
satisfy a liability that has been so assumed in circumstances in which Reliant
Energy and its subsidiaries were not released from the liability in connection
with the transfer, we and, CenterPoint Energy could be responsible for
satisfying the liability.
Prior to
CenterPoint Energy's distribution of its ownership in RRI to its shareholders,
we had guaranteed certain contractual obligations of what became RRI’s trading
subsidiary. When the companies separated, RRI agreed to secure us against
obligations under the guaranties RRI had been unable to extinguish by the time
of separation. Pursuant to such agreement, as amended in December 2007, RRI has
agreed to provide us cash or letters of credit as security against our
obligations under its remaining guaranties if and to the extent changes in
market conditions expose us to a risk of loss on those guaranties. As of
September 30, 2009, RRI was not required to provide security to us. If RRI
should fail to perform the contractual obligations, we could have to honor our
guarantee and, in such event, collateral provided as security may be
insufficient to satisfy our obligations.
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 $99 million as of September 30, 2009. 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.
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 for
certain liabilities, including their indemnification regarding certain
litigation, nor does it affect the terms of existing guaranty arrangements for
certain RRI gas transportation contracts.
Reliant
Energy and RRI are named as defendants in a number of lawsuits arising out of
energy sales in California and other markets and financial reporting matters.
Although these matters relate to the business and operations of RRI, claims
against Reliant Energy have been made on grounds that include the effect of
RRI’s financial results on Reliant Energy’s historical financial statements and
liability of Reliant Energy as a controlling shareholder of RRI. We or
CenterPoint Energy could incur liability if claims in one or more of these
lawsuits were successfully asserted against us, 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 and the proceeds of equity
financing may be materially adversely impacted by these market conditions.
Defaults of lenders in our credit facility 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 non-
cash
pension expense in 2009, which will impact 2009 results of operations and may
impact liquidity if contributions are made to offset reduced asset
values.
In
addition to the credit and financial market issues, 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.
Our ratio
of earnings to fixed charges for the nine months ended September 30, 2008
and 2009 was 3.18 and 2.24, respectively. We do not believe that the ratios for
these nine-month periods are necessarily indicative 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.
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 |
|
|
|
|
|
|
|
|
Exhibit
Number
|
|
Description
|
|
Report
or Registration
Statement
|
|
SEC
File or
Registration
Number
|
|
Exhibit
Reference
|
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: November
10, 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
|
|
|
|
|
|
|
|
|
ex12.htm
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)
|
|
Nine
Months Ended September 30,
|
|
|
|
2008 (1)
|
|
|
2009 (1)
|
|
|
|
|
|
|
|
|
Net
Income
|
|
$ |
253 |
|
|
$ |
134 |
|
Equity
in earnings of unconsolidated affiliates |
|
|
(46 |
) |
|
|
(8 |
) |
Income
taxes
|
|
|
153 |
|
|
|
86 |
|
Capitalized
interest
|
|
|
(5 |
) |
|
|
(2 |
) |
|
|
|
355 |
|
|
|
210 |
|
|
|
|
|
|
|
|
|
|
Fixed
charges, as defined:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
|
148 |
|
|
|
159 |
|
Capitalized
interest
|
|
|
5 |
|
|
|
2 |
|
Interest
component of rentals charged to operating income
|
|
|
10 |
|
|
|
8 |
|
Total
fixed
charges
|
|
|
163 |
|
|
|
169 |
|
|
|
|
|
|
|
|
|
|
Earnings,
as defined
|
|
$ |
518 |
|
|
$ |
379 |
|
|
|
|
|
|
|
|
|
|
Ratio
of earnings to fixed charges
|
|
|
3.18 |
|
|
|
2.24 |
|
________
|
(1)
|
Excluded
from the computation of fixed charges for each of the nine months ended
September 30, 2008 and 2009 is interest income of $1 million, which is
included in income tax
expense.
|
ex31-1.htm
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;
|
|
(c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
(d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
5. The
registrant’s other certifying officer(s) and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
|
(a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
(b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
Date: November
10, 2009
|
/s/
David M. McClanahan
|
|
David
M. McClanahan
|
|
President
and Chief Executive
Officer
|
ex31-2.htm
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:
|
(a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
(b)
|
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
|
(c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
(d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
5. The
registrant’s other certifying officer(s) and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
|
(a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
(b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
Date: November
10, 2009
|
/s/
Gary L. Whitlock
|
|
Gary
L. Whitlock
|
|
Executive
Vice President and Chief Financial
Officer
|
ex32-1.htm
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 September 30, 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.
/s/
David M. McClanahan
|
|
David
M. McClanahan
|
|
President
and Chief Executive Officer
|
|
November 10,
2009
|
|
ex32-2.htm
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 September 30, 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
|
|
Gary
L. Whitlock
|
|
Executive
Vice President and Chief Financial Officer
|
|
November 10,
2009
|
|