UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM __________ TO __________.
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Commission file number 1-13265
CENTERPOINT ENERGY RESOURCES CORP.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0511406
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1111 LOUISIANA (713) 207-1111
HOUSTON, TEXAS 77002 (Registrant's telephone number,
(Address and zip code of including area code)
principal executive offices)
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 X No
----- -----
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes No X
----- -----
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes No X
----- -----
As of November 1, 2005, 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, 2005
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements....................................................... 1
Statements of Consolidated Operations
Three Months and Nine Months Ended September 30, 2004 and 2005 (unaudited)... 1
Consolidated Balance Sheets
December 31, 2004 and September 30, 2005 (unaudited)......................... 2
Statements of Consolidated Cash Flows
Nine Months Ended September 30, 2004 and 2005 (unaudited).................... 4
Notes to Unaudited Consolidated Financial Statements............................ 5
Item 2. Management's Narrative Analysis of the Results of Operations............... 16
Item 4. Controls and Procedures.................................................... 25
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.......................................................... 26
Item 5. Other Information.......................................................... 26
Item 6. Exhibits................................................................... 29
i
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:
- state and federal legislative and regulatory actions or developments,
constraints placed on our activities or business by the Public Utility
Holding Company Act of 1935, as amended (1935 Act), the impact of the
repeal of the 1935 Act and changes in or application of laws or
regulations applicable to other aspects of our business and actions
with respect to:
- allowed rates of return;
- rate structures;
- recovery of investments; and
- operation and construction of facilities;
- timely rate increases, including recovery of costs;
- industrial, commercial and residential growth in our service territory
and changes in market demand and demographic patterns;
- the timing and extent of changes in commodity prices, particularly
natural gas;
- changes in interest rates or rates of inflation;
- weather variations and other natural phenomena;
- the timing and extent of changes in the supply of natural gas;
- commercial bank and financial market conditions, our access to
capital, the costs of such capital, receipt of certain financing
approvals under the 1935 Act, and the results of our financing and
refinancing efforts, including availability of funds in the debt
capital markets;
- actions by rating agencies;
- effectiveness of our risk management activities;
- inability of various counterparties to meet their obligations to us;
- non-payment of our services due to financial distress of our
customers;
- our ability to control costs;
- the investment performance of CenterPoint Energy's employee benefit
plans;
ii
- our potential business strategies, including acquisitions or
dispositions of assets or businesses, which cannot be assured to be
completed or to have the anticipated benefits to us; and
- other factors we discuss in "Risk Factors" in Item 5 of Part II of
this report beginning on page 26.
Additional risk factors are described in other documents we file 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.
iii
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED OPERATIONS
(MILLIONS OF DOLLARS)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2004 2005 2004 2005
------ ------ ------ ------
REVENUES ............................... $1,219 $1,732 $4,739 $5,663
------ ------ ------ ------
EXPENSES:
Natural gas ......................... 928 1,422 3,701 4,563
Operation and maintenance ........... 184 188 536 532
Depreciation and amortization ....... 47 50 139 149
Taxes other than income taxes ....... 28 32 107 108
------ ------ ------ ------
Total ............................ 1,187 1,692 4,483 5,352
------ ------ ------ ------
OPERATING INCOME ....................... 32 40 256 311
------ ------ ------ ------
OTHER INCOME (EXPENSE):
Interest and other finance charges .. (45) (39) (134) (136)
Other, net .......................... 4 6 10 18
------ ------ ------ ------
Total ............................ (41) (33) (124) (118)
------ ------ ------ ------
INCOME (LOSS) BEFORE INCOME TAXES ...... (9) 7 132 193
Income Tax (Expense) Benefit ........ 7 (3) (49) (66)
------ ------ ------ ------
NET INCOME (LOSS) ...................... $ (2) $ 4 $ 83 $ 127
====== ====== ====== ======
See Notes to the Company's Interim Financial Statements
1
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS
(MILLIONS OF DOLLARS)
(UNAUDITED)
ASSETS
DECEMBER 31, SEPTEMBER 30,
2004 2005
------------ -------------
CURRENT ASSETS:
Cash and cash equivalents .................................. $ 141 $ 107
Accounts and notes receivable, net ......................... 613 587
Accrued unbilled revenue ................................... 502 189
Accounts and notes receivable - affiliated companies, net .. 12 --
Materials and supplies ..................................... 25 32
Natural gas inventory ...................................... 174 310
Non-trading derivative assets .............................. 50 195
Taxes receivable ........................................... 155 1
Deferred tax asset ......................................... 12 2
Prepaid expenses ........................................... 9 10
Other ...................................................... 92 233
------ ------
Total current assets .................................... 1,785 1,666
------ ------
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment .............................. 4,296 4,508
Less accumulated depreciation .............................. (462) (524)
------ ------
Property, plant and equipment, net ...................... 3,834 3,984
------ ------
OTHER ASSETS:
Goodwill, net .............................................. 1,741 1,744
Other intangibles, net ..................................... 20 19
Non-trading derivative assets .............................. 18 108
Accounts and notes receivable - affiliated companies, net .. 18 16
Other ...................................................... 117 138
------ ------
Total other assets ...................................... 1,914 2,025
------ ------
TOTAL ASSETS .................................................. $7,533 $7,675
====== ======
See Notes to the Company's Interim Financial Statements
2
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
(MILLIONS OF DOLLARS)
(UNAUDITED)
LIABILITIES AND STOCKHOLDER'S EQUITY
DECEMBER 31, SEPTEMBER 30,
2004 2005
------------ -------------
CURRENT LIABILITIES:
Current portion of long-term debt ....................... $ 367 $ 6
Accounts payable ........................................ 799 784
Accounts and notes payable - affiliated companies, net .. -- 13
Taxes accrued ........................................... 78 63
Interest accrued ........................................ 58 46
Customer deposits ....................................... 60 60
Non-trading derivative liabilities ...................... 26 89
Accumulated deferred income taxes, net .................. -- 2
Other ................................................... 273 559
------ ------
Total current liabilities ............................ 1,661 1,622
------ ------
OTHER LIABILITIES:
Accumulated deferred income taxes, net .................. 641 637
Non-trading derivative liabilities ...................... 6 14
Benefit obligations ..................................... 128 129
Other ................................................... 557 659
------ ------
Total other liabilities .............................. 1,332 1,439
------ ------
LONG-TERM DEBT ............................................. 2,001 1,986
------ ------
COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 9)
STOCKHOLDER'S EQUITY:
Common stock ............................................ -- --
Paid-in capital ......................................... 2,232 2,292
Retained earnings ....................................... 305 332
Accumulated other comprehensive income .................. 2 4
------ ------
Total stockholder's equity ........................... 2,539 2,628
------ ------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY .............. $7,533 $7,675
====== ======
See Notes to the Company's Interim Financial Statements
3
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED CASH FLOWS
(MILLIONS OF DOLLARS)
(UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2004 2005
----- -----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................................. $ 83 $ 127
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation and amortization ....................................... 139 149
Amortization of deferred financing costs ............................ 7 6
Deferred income taxes ............................................... 9 (2)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net ................... 343 339
Accounts receivable/payable, affiliates .......................... (23) (10)
Inventory ........................................................ (81) (134)
Taxes receivable ................................................. 21 214
Accounts payable ................................................. (144) --
Fuel cost recovery ............................................... 43 (69)
Interest and taxes accrued ....................................... (3) (26)
Net non-trading derivative assets and liabilities ................ (18) 6
Margin deposits, net ............................................. 15 78
Short-term risk management activities, net ....................... 1 (19)
Other current assets ............................................. (23) (41)
Other current liabilities ........................................ (4) 65
Other assets ..................................................... (6) 6
Other liabilities ................................................ (8) --
Other, net .......................................................... (3) (2)
----- -----
Net cash provided by operating activities ........................ 348 687
----- -----
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ................................................... (170) (280)
Decrease (increase) in notes receivable from affiliates ................ (83) 38
Other, net ............................................................. (4) (5)
----- -----
Net cash used in investing activities ............................ (257) (247)
----- -----
CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term borrowings, net ................................. (63) --
Payments of long-term debt ............................................. -- (372)
Decrease in notes payable with affiliates .............................. (32) (1)
Debt issuance costs .................................................... (2) (1)
Dividend to parent ..................................................... (12) (100)
----- -----
Net cash used in financing activities ............................ (109) (474)
----- -----
NET DECREASE IN CASH AND CASH EQUIVALENTS ................................. (18) (34)
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE PERIOD ...................... 34 141
----- -----
CASH AND CASH EQUIVALENTS AT END OF THE PERIOD ............................ $ 16 $ 107
===== =====
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest ............................................................... $ 137 $ 142
Income taxes ........................................................... 73 91
See Notes to the Company's Interim Financial Statements
4
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
NOTES TO UNAUDITED 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. are the consolidated interim financial
statements and notes (Interim Financial Statements) of CenterPoint Energy
Resources Corp. and its subsidiaries (collectively, CERC Corp. or the Company).
The Interim 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, 2004 (CERC Corp. Form 10-K).
Background. The Company's operating subsidiaries own and operate natural
gas distribution facilities, interstate pipelines and natural gas gathering,
processing and treating facilities. The Company's operations of its local
distribution companies are conducted through two unincorporated divisions:
Minnesota Gas and Southern Gas Operations, which includes Houston Gas. Through
wholly owned subsidiaries, the Company owns two interstate natural gas pipelines
and gas gathering systems, provides various ancillary services, and offers
variable and fixed-price physical natural gas supplies to commercial and
industrial customers and natural gas distributors.
The Company is an indirect wholly owned subsidiary of CenterPoint Energy,
Inc. (CenterPoint Energy), a public utility holding company created on August
31, 2002, as part of a corporate restructuring of Reliant Energy, Incorporated
(Reliant Energy) that implemented certain requirements of the Texas Electric
Choice Plan. CenterPoint Energy is a registered public utility holding company
under the Public Utility Holding Company Act of 1935, as amended (1935 Act). The
1935 Act and related rules and regulations impose a number of restrictions on
the activities of CenterPoint Energy and those of its subsidiaries. The 1935
Act, among other things, limits the ability of CenterPoint Energy and its
subsidiaries to issue debt and equity securities without prior authorization,
restricts the source of dividend payments to current and retained earnings
without prior authorization, regulates sales and acquisitions of certain assets
and businesses and governs affiliated service, sales and construction contracts.
On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005
(Energy Act). Under that legislation, the 1935 Act is repealed effective
February 8, 2006. After the effective date of the repeal, CenterPoint Energy and
its subsidiaries will no longer be subject to restrictions imposed under the
1935 Act. Until the repeal is effective, CenterPoint Energy and its subsidiaries
remain subject to the provisions of the 1935 Act and the terms of orders issued
by the Securities and Exchange Commission (SEC) under the 1935 Act. The Energy
Act grants to the Federal Energy Regulatory Commission (FERC) authority to
require holding companies and their subsidiaries to maintain certain books and
records and make them available for review by FERC and state regulatory
authorities. The Energy Act requires FERC to issue regulations to implement its
jurisdiction under the Energy Act, and on September 16, 2005, FERC issued
proposed rules for public comment. It is presently unknown what, if any,
specific obligations under those rules may be imposed on CenterPoint Energy and
its subsidiaries as a result of that rulemaking.
Basis of Presentation. The preparation of financial statements in
conformity with generally accepted accounting principles in the United States of
America (GAAP) requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results
could differ from those estimates.
The Company's Interim Financial Statements reflect all normal recurring
adjustments that are, in the opinion of management, necessary to present fairly
the financial position, results of operations and cash flows for the respective
periods. Amounts reported in the Company's Statements of Consolidated Operations
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.
Note 2(e) (Regulatory Assets and Liabilities), Note 3 (Regulatory Matters),
Note 5 (Derivative Instruments) and Note 9 (Commitments and Contingencies) to
the consolidated annual financial statements in the CERC Corp. Form
5
10-K (CERC Corp. 10-K Notes) relate to certain contingencies. These notes, as
updated herein, are incorporated herein by reference.
For information regarding environmental matters and legal proceedings, see
Note 9 to the Interim Financial Statements.
(2) NEW ACCOUNTING PRONOUNCEMENTS
In May 2005, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 154, "Accounting Changes
and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement
No. 3" (SFAS No. 154). SFAS No. 154 provides guidance on the accounting for and
reporting of accounting changes and error corrections. It establishes, unless
impracticable, retrospective application as the required method for reporting a
change in accounting principle in the absence of explicit transition
requirements specific to the newly adopted accounting principle. The correction
of an error in previously issued financial statements is not an accounting
change and must be reported as a prior-period adjustment by restating previously
issued financial statements. SFAS No. 154 is effective for accounting changes
and corrections of errors made in fiscal years beginning after December 15,
2005.
In March 2005, the FASB issued FASB Interpretation No. (FIN) 47,
"Accounting for Conditional Asset Retirement Obligations" (FIN 47). FIN 47
clarifies that an entity must record a liability for a "conditional" asset
retirement obligation if the fair value of the obligation can be reasonably
estimated. FIN 47 is effective no later than the end of fiscal years ending
after December 15, 2005. The Company is evaluating the effect of adoption of
this new standard on its financial position, results of operations and cash
flows.
(3) REGULATORY MATTERS
(a) Rate Cases.
In November 2004, Southern Gas Operations filed an application for a $28
million base rate increase, as adjusted, with the Arkansas Public Service
Commission (APSC). In September 2005, the APSC ordered an $11 million rate
reduction, including a $10 million reduction relating to depreciation rates,
which went into effect on September 25, 2005.
In April 2005, the Railroad Commission of Texas (Railroad Commission)
approved a settlement that increased Southern Gas Operations' base rate and
service revenues by a combined $2 million in the unincorporated environs of its
Beaumont/East Texas and South Texas Divisions. In June and August 2005, Southern
Gas Operations filed requests to implement these rates within the incorporated
cities located in its Beaumont/East Texas and South Texas Divisions. If these
rates are approved in all jurisdictions as requested, Southern Gas Operations'
base rate and service revenues are expected to increase by an additional $16
million annually.
In June 2005, the Minnesota Public Utilities Commission (MPUC) approved a
settlement which increases Minnesota Gas' base rates by approximately $9 million
annually. An interim rate increase of $17 million had been implemented in
October 2004. Substantially all of the excess amounts collected in interim rates
over those approved in the final settlement were refunded to customers in the
third quarter.
On November 2, 2005, Minnesota Gas filed a request with the MPUC to
increase annual rates by $41 million. It has requested that an interim rate
increase of $35 million be implemented January 1, 2006. Any difference between
the interim rates collected and the final rates would be subject to refund to
customers. A decision by the MPUC is expected in the third quarter of 2006.
(b) City of Tyler, Texas Dispute.
In July 2002, the City of Tyler, Texas, asserted that Southern Gas
Operations had overcharged residential and small commercial customers in that
city for gas costs under supply agreements in effect since 1992. That dispute
was referred to the Railroad Commission by agreement of the parties for a
determination of whether Southern Gas Operations has properly charged and
collected for gas service to its residential and commercial customers in its
Tyler distribution system in accordance with lawful filed tariffs during the
period beginning November 1, 1992, and
6
ending October 31, 2002. In December 2004, the Railroad Commission conducted a
hearing on the matter. On May 25, 2005, the Railroad Commission issued a final
order finding that the Company had complied with its tariffs, acted prudently in
entering into its gas supply contracts, and prudently managed those contracts.
On August 10, 2005, the City of Tyler appealed this order to the Court of
Appeals.
(c) Settlement of FERC Audit.
On June 27, 2005, CenterPoint Energy Gas Transmission Company (CEGT), a
subsidiary of CERC Corp., received an Order from FERC accepting the terms of a
settlement agreed upon by CEGT with the Staff of the FERC's Office of Market
Oversight and Investigations (OMOI). The settlement brought to a conclusion an
investigation of CEGT initiated by OMOI in August 2003. Among other things, the
investigation involved a comprehensive review of CEGT's relationship with its
marketing affiliates and compliance with various FERC record-keeping and
reporting requirements covering the period from January 1, 2001 through
September 22, 2004.
OMOI Staff took the position that some of CEGT's actions resulted in a
limited number of violations of FERC's affiliate regulations or were in
violation of certain record-keeping and administrative requirements. OMOI did
not find any systematic violations of its rules governing communications or
other relationships among affiliates.
The settlement included two remedies: a payment of a $270,000 civil penalty
and the execution of a compliance plan, applicable to both CEGT and CenterPoint
Energy-Mississippi River Transmission Corporation (MRT). The compliance plan
consists of a detailed set of Implementation Procedures that will facilitate
compliance with FERC's Order No. 2004, the Standards of Conduct, which regulate
behavior between regulated entities and their affiliates. The Company does not
believe the compliance plan will have any material effect on CEGT's or MRT's
ability to conduct their business.
(4) DERIVATIVE FINANCIAL INSTRUMENTS
The Company is exposed to various market risks. These risks arise from
transactions entered into in the normal course of business. The Company utilizes
derivative financial instruments such as physical forward contracts, swaps and
options to mitigate the impact of changes in cash flows of its natural gas
businesses on its operating results and cash flows.
Cash Flow Hedges. During the nine months ended September 30, 2004 and 2005,
hedge ineffectiveness was less than $1 million from derivatives that qualify for
and are designated as cash flow hedges. No component of the derivative
instruments' gain or loss was excluded from the assessment of effectiveness. If
it becomes probable that an anticipated transaction will not occur, the Company
realizes in net income the deferred gains and losses recognized in accumulated
other comprehensive loss. Once the anticipated transaction occurs, the
accumulated deferred gain or loss recognized in accumulated other comprehensive
loss is reclassified and included in the Company's Statements of Consolidated
Operations under the caption "Natural Gas." Cash flows resulting from these
transactions in non-trading energy derivatives are included in the Statements of
Consolidated Cash Flows in the same category as the item being hedged. As of
September 30, 2005, the Company expects $(0.4) million in accumulated other
comprehensive loss to be reclassified into net income during the next twelve
months.
Other Derivative Financial Instruments. The Company also has natural gas
contracts that are derivatives which are not hedged and are accounted for on a
mark-to-market basis with changes in fair value reported through earnings. Load
following services that the Company offers its natural gas customers create an
inherent tendency for the Company to be either long or short natural gas
supplies relative to customer purchase commitments. The Company measures and
values all of its volumetric imbalances on a real-time basis to minimize its
exposure to commodity price and volume risk. The Company does not engage in
proprietary or speculative commodity trading. Unhedged positions are accounted
for by adjusting the carrying amount of the contracts to market and recognizing
any gain or loss in operating income, net. During the nine months ended
September 30, 2004 and 2005, the Company recognized net gains (losses) related
to unhedged positions amounting to $(4) million and $14 million, respectively.
As of December 31, 2004, the Company had recorded short-term risk management
assets and liabilities of $4 million and $5 million, respectively, included in
other current assets and other current liabilities, respectively. As of
September 30, 2005, the Company had recorded short-term risk management assets
and liabilities of $55 million and $37 million, respectively, included in other
current assets and other current liabilities, respectively.
7
A portion of CenterPoint Energy Services, Inc.'s (CES) activities include
entering into transactions for the physical purchase, transportation and sale of
natural gas at different locations (physical contracts). CES attempts to
mitigate basis risk associated with these activities by entering into financial
derivative contracts (financial contracts or financial basis swaps) to address
market price volatility between the purchase and sale delivery points that can
occur over the term of the physical contracts. The underlying physical contracts
are accounted for on an accrual basis with all associated earnings not
recognized until the time of actual physical delivery. The timing of the
earnings impacts for the financial contracts differs from the physical contracts
because the financial contracts meet the definition of a derivative under SFAS
No. 133, "Accounting for Derivative Instruments" (SFAS No. 133), and are
recorded at fair value as of each reporting balance sheet date with changes in
value reported through earnings. Changes in prices between the delivery points
(basis spreads) can and do vary daily resulting in changes to the fair value of
the financial contracts. However, the economic intent of the financial contracts
is to fix the actual net difference in the natural gas pricing at the different
locations for the associated physical purchase and sale contracts throughout the
life of the physical contracts and thus, when combined with the physical
contracts' terms, provide an expected fixed gross margin on the physical
contracts that will ultimately be recognized in earnings at the time of actual
delivery of the natural gas. As of September 30, 2005, the mark-to-market value
of the financial contracts described above reflected an unrealized loss of $3.6
million; however, the underlying expected fixed gross margin associated with
delivery under the physical contracts combined with the price risk management
provided through the financial contracts is $2.3 million. As described above,
over the term of these financial contracts, the quarterly reported
mark-to-market changes in value may vary significantly and the associated
unrealized gains and losses will be reflected in CES' earnings.
CES also sells physical gas and basis to its end-use customers who desire
to lock in a future spread between a specific location and Henry Hub (NYMEX). As
a result, CES incurs exposure to commodity basis risk related to these
transactions, which it attempts to mitigate by buying offsetting financial basis
swaps. Under SFAS No. 133, CES records at fair value and marks-to-market the
financial basis swaps as of each reporting balance sheet date with changes in
value reported through earnings. However, the associated physical sales
contracts are accounted for using the accrual basis, whereby earnings impacts
are not recognized until the time of actual physical delivery. Although the
timing of earnings recognition for the financial basis swaps differs from the
physical contracts, the economic intent of the financial basis swaps is to fix
the basis spread over the life of the physical contracts to an amount
substantially the same as the portion of the basis spread pricing included in
the physical contracts. In so doing, over the period that the financial basis
swaps and related physical contracts are outstanding, actual cumulative earnings
impacts for changes in the basis spread should be minimal, even though from a
timing perspective there could be fluctuations in unrealized gains or losses
associated with the changes in fair value recorded for the financial basis
swaps. The cumulative earnings impact from the financial basis swaps recognized
each reporting period is expected to be offset by the value realized when the
related physical sales occur. As of September 30, 2005, the mark-to-market value
of the financial basis swaps reflected an unrealized loss of $4.8 million.
(5) GOODWILL AND INTANGIBLES
Goodwill by reportable business segment is as follows (in millions):
DECEMBER 31, 2004 SEPTEMBER 30,
2004 2005
----------------- --------------
Natural Gas Distribution .. $1,085 $1,085
Pipelines and Gathering ... 601 604
Other Operations .......... 55 55
------ ------
Total .................. $1,741 $1,744
====== ======
The Company performs its goodwill impairment test at least annually and
evaluates goodwill when events or changes in circumstances indicate that the
carrying value of these assets may not be recoverable. Upon adoption of SFAS No.
142, "Goodwill and Other Intangible Assets," the Company initially selected
January 1 as its annual goodwill impairment testing date. Since the time the
Company selected the January 1 date, the Company's year-end closing and
reporting process has been truncated in order to meet the accelerated reporting
requirements of the SEC, resulting in significant constraints on the Company's
human resources at year-end and during its first fiscal quarter. Accordingly, in
order to meet the accelerated reporting deadlines and to provide adequate time
to complete the analysis each year, beginning in the third quarter of 2005, the
Company changed the date on which it performs its
8
annual goodwill impairment test from January 1 to July 1. The Company believes
the July 1 alternative date will alleviate the resource constraints that exist
during the first quarter and allow it to utilize additional resources in
conducting the annual impairment evaluation of goodwill. The Company performed
the test at July 1, 2005, and determined that no impairment charge for goodwill
was required. The change is not intended to delay, accelerate or avoid an
impairment charge. The Company believes that this accounting change is an
alternative accounting principle that is preferable under the circumstances.
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2004 SEPTEMBER 30, 2005
----------------------- -----------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Land use rights................................. $ 7 $(3) $ 7 $ (3)
Other........................................... 21 (5) 22 (7)
--- --- --- ----
Total........................................... $28 $(8) $29 $(10)
=== === === ====
The Company recognizes specifically identifiable intangibles, including
land use rights and permits, when specific rights and contracts are acquired.
The Company has no intangible assets with indefinite lives recorded as of
September 30, 2005. The Company amortizes other acquired intangibles on a
straight-line basis over the lesser of their contractual or estimated useful
lives that range from 47 to 75 years for land use rights and 4 to 25 years for
other intangibles.
Amortization expense for other intangibles for both the three months ended
September 30, 2004 and 2005 was $0.4 million. Amortization expense for other
intangibles for the nine months ended September 30, 2004 and 2005 was $1.3
million and $1.4 million, respectively. Estimated amortization expense for the
remainder of 2005 is approximately $0.5 million and is approximately $2 million
per year for each of the five succeeding fiscal years.
(6) LONG-TERM DEBT AND RECEIVABLES FACILITY
(a) Long-Term Debt.
Credit Facilities. In June 2005, the Company replaced its $250 million
three-year revolving credit facility with a $400 million five-year revolving
credit facility. The new credit facility terminates on June 30, 2010. Borrowings
under this facility may be made at the London interbank offered rate (LIBOR)
plus 55 basis points, including the facility fee, based on current credit
ratings. An additional utilization fee of 10 basis points applies to borrowings
whenever more than 50% of the facility is utilized. Changes in credit ratings
could lower or raise the increment to LIBOR depending on whether ratings
improved or were lowered. As of September 30, 2005, such credit facility was not
utilized.
Junior Subordinated Debentures (Trust Preferred Securities). In June 1996,
a Delaware statutory business trust created by CERC Corp. (CERC Trust) issued
$173 million aggregate amount of convertible preferred securities to the public.
CERC Trust used the proceeds of the offering to purchase convertible junior
subordinated debentures issued by CERC Corp. having an interest rate and
maturity date that correspond to the distribution rate and mandatory redemption
date of the convertible preferred securities. CERC Corp. considers its
obligation under the Amended and Restated Declaration of Trust, Indenture and
Guaranty Agreement relating to the convertible preferred securities, taken
together, to constitute a full and unconditional guarantee by CERC Corp. of CERC
Trust's obligations with respect to the convertible preferred securities. The
convertible junior subordinated debentures represented CERC Trust's sole asset
and its entire operations. The amount of outstanding junior subordinated
debentures was included in long-term debt as of December 31, 2004. On July 1,
2005, the remaining $0.3 million of convertible preferred securities and the $6
million of related convertible junior subordinated debentures were called for
redemption on August 1, 2005. Most of the convertible preferred securities were
converted prior to the redemption date and the remaining securities were
redeemed.
9
(b) Receivables Facility.
In January 2005, the Company's $250 million receivables facility was
extended to January 2006 and temporarily increased, for the period from January
2005 to June 2005, to $375 million to provide additional liquidity to the
Company during the peak heating season of 2005. As of September 30, 2005, the
Company had $141 million of advances under its receivables facility.
Advances under the receivables facility averaged $173 million for the nine
months ended September 30, 2005. Sales of receivables were approximately $447
million and $480 million for the three months ended September 30, 2004 and 2005,
respectively, and $1.7 billion and $1.4 billion for the nine months ended
September 30, 2004 and 2005, respectively.
(7) COMPREHENSIVE INCOME
The following table summarizes the components of total comprehensive income
(net of tax):
FOR THE THREE MONTHS FOR THE NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
-------------------- -------------------
2004 2005 2004 2005
---- ---- ---- ----
(IN MILLIONS)
Net income (loss) ........................................... $(2) $ 4 $ 83 $127
--- --- ---- ----
Other comprehensive income (loss):
Net deferred gain from cash flow hedges .................. 17 1 34 11
Reclassification of deferred gain from cash flow hedges
realized in net income ................................ (6) (7) (14) (9)
--- --- ---- ----
Other comprehensive income (loss) ........................... 11 (6) 20 2
--- --- ---- ----
Comprehensive income (loss) ................................. $ 9 $(2) $103 $129
=== === ==== ====
The following table summarizes the components of accumulated other
comprehensive income:
DECEMBER 31, SEPTEMBER 30,
2004 2005
------------ -------------
(IN MILLIONS)
Net deferred gain from cash flow hedges... $2 $4
== ==
(8) RELATED PARTY TRANSACTIONS
The following table summarizes receivables from, or payables to,
CenterPoint Energy or its subsidiaries:
DECEMBER 31, SEPTEMBER 30,
2004 2005
------------ -------------
(IN MILLIONS)
Accounts receivable from affiliates...................................... $ 4 $ 11
Accounts payable to affiliates........................................... (34) (28)
Notes receivable from affiliates(1)...................................... 42 4
---- ----
Accounts and notes receivable/(payable) -- affiliated companies, net.. $ 12 $(13)
==== ====
Long-term accounts receivable from affiliates............................ $ 64 $ 64
Long-term accounts payable to affiliates................................. (45) (48)
Long-term notes payable to affiliates.................................... (1) --
---- ----
Long-term accounts and notes receivable -- affiliated companies, net.. $ 18 $ 16
==== ====
- ----------
(1) Represents money pool investments.
For the three months ended September 30, 2004 and 2005, the Company had net
interest income related to affiliate borrowings of $2.9 million and $0.9
million, respectively. For the nine months ended September 30, 2004 and 2005,
the Company had net interest income related to affiliate borrowings of $7.0
million and $3.5 million, respectively.
10
The 1935 Act generally prohibits borrowings by CenterPoint Energy from its
subsidiaries, including the Company, either through the money pool or otherwise.
For the three and nine months ended September 30, 2004, the sales and
services provided by the Company to Texas Genco Holdings, Inc. (Texas Genco), a
former subsidiary of CenterPoint Energy, totaled $3 million and $20 million,
respectively. For the three and nine months ended September 30, 2005, the
Company provided no sales or services to CenterPoint Energy or its subsidiaries.
CenterPoint Energy provides some corporate services to the Company. The
costs of services have been directly charged to the Company using methods that
management believes are reasonable. These methods include negotiated usage
rates, dedicated asset assignment, and proportionate corporate formulas based on
assets, operating margins, operating expenses and employees. These charges are
not necessarily indicative of what would have been incurred had the Company not
been an affiliate. Amounts charged to the Company for these services were $29
million and $33 million for the three months ended September 30, 2004 and 2005,
respectively, and $84 million and $93 million for the nine months ended
September 30, 2004 and 2005, respectively, and are included primarily in
operation and maintenance expenses.
Pursuant to the tax sharing agreement with CenterPoint Energy, the Company
received an allocation of CenterPoint Energy's tax benefits totaling $5 million
and $60 million for the three and nine months ended September 30, 2005,
respectively, which was recorded as an increase to additional paid-in capital.
In the second quarter of 2005, the Company paid a dividend of $100 million
to Utility Holding, LLC, the Company's parent.
(9) COMMITMENTS AND CONTINGENCIES
(a) Legal Matters.
Natural Gas Measurement Lawsuits. CERC Corp. and certain of its
subsidiaries are defendants in a suit 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 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 of the Company's subsidiaries), limited the
scope of the class of plaintiffs they purport to represent and eliminated
previously asserted claims based on mismeasurement of the Btu content of the
gas. The same plaintiffs then filed a second lawsuit, again as representatives
of a class of royalty owners, in which they assert their claims that the
defendants have engaged in systematic mismeasurement of the Btu content of
natural gas for more than 25 years. In both lawsuits, the plaintiffs seek
compensatory damages, along with statutory penalties, treble damages, interest,
costs and fees. The Company believes that there has been no systematic
mismeasurement of gas and that the suits are without merit. The Company does not
expect the ultimate outcome to have a material impact on its financial
condition, results of operations or cash flows.
Gas Cost Recovery Litigation. In October 2002, a suit was filed in state
district court in Wharton County, Texas against the Company, CenterPoint Energy,
Entex Gas Marketing Company, and certain non-affiliated companies alleging
fraud, violations of the Texas Deceptive Trade Practices Act, violations of the
Texas Utilities Code, civil
11
conspiracy and violations of the Texas Free Enterprise and Antitrust Act with
respect to rates charged to certain consumers of natural gas in the State of
Texas. Subsequently the plaintiffs added as defendants CenterPoint Energy
Marketing Inc., CenterPoint Energy Gas Transmission Company, United Gas, Inc.,
Louisiana Unit Gas Transmission Company, CenterPoint Energy Pipeline Services,
Inc., and CenterPoint Energy Trading and Transportation Group, Inc., all of
which are subsidiaries of the Company. The plaintiffs alleged that defendants
inflated the prices charged to certain consumers of natural gas. In February
2003, a similar suit was filed in state court in Caddo Parish, Louisiana against
the Company with respect to rates charged to a purported class of certain
consumers of natural gas and gas service in the State of Louisiana. In February
2004, another suit was filed in state court in Calcasieu Parish, Louisiana
against the Company seeking to recover alleged overcharges for gas or gas
services allegedly provided by Southern Gas Operations to a purported class of
certain consumers of natural gas and gas service without advance approval by the
Louisiana Public Service Commission (LPSC). In October 2004, a similar case was
filed in district court in Miller County, Arkansas against the Company,
CenterPoint Energy, Entex Gas Marketing Company, CenterPoint Energy Gas
Transmission Company, CenterPoint Energy Field Services, CenterPoint Energy
Pipeline Services, Inc., Mississippi River Transmission Corp. and other
non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy
with respect to rates charged to certain consumers of natural gas in at least
the states of Arkansas, Louisiana, Mississippi, Oklahoma and Texas. At the time
of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in
those cases filed petitions with the LPSC relating to the same alleged rate
overcharges. The Caddo and Calcasieu Parish cases have been stayed pending the
resolution of the respective proceedings by the LPSC. The plaintiffs in the
Miller County case seek class certification, but the proposed class has not been
certified. In November 2004, the Miller case was removed to federal district
court in Texarkana, Arkansas. In February 2005, the Wharton County case was
removed to federal district court in Houston, Texas, and in March 2005, the
plaintiffs voluntarily moved to dismiss the case and agreed not to refile the
claims asserted unless the Miller County case is not certified as a class action
or is later decertified. In June 2005, the Miller County case was remanded to
state district court in Miller County. The range of relief sought by the
plaintiffs in these cases includes injunctive and declaratory relief,
restitution for the alleged overcharges, exemplary damages or trebling of actual
damages, civil penalties and attorney's fees. In these cases, the Company,
CenterPoint Energy and their affiliates deny that they have overcharged any of
their customers for natural gas and believe that the amounts recovered for
purchased gas have been in accordance with what is permitted by state regulatory
authorities. The allegations in these cases are similar to those asserted in the
City of Tyler proceeding described in Note 3(b). The Company and CenterPoint
Energy do not expect the outcome of these matters to have a material impact on
the financial condition, results of operations or cash flows of either the
Company or CenterPoint Energy.
Pipeline Safety Compliance. In 2005, the Company received an order from the
Minnesota Office of Pipeline Safety to remove certain components from a portion
of its distribution system by December 2, 2005. Those components were installed
by a predecessor company and are not in compliance with current state and
federal codes. The Company estimates the amount of expenditures to locate and
replace such components to be approximately $38 million. The Company is seeking
to recover the capitalized expenditures, together with a return on those amounts
through rates.
Minnesota Cold Weather Rule. In December 2004, the MPUC opened an
investigation to determine whether the Company's practices regarding restoring
natural gas service during the period between October 15 and April 15 (Cold
Weather Period) are in compliance with the MPUC's Cold Weather Rule (CWR), which
governs disconnection and reconnection of customers during the Cold Weather
Period. The Minnesota Office of the Attorney General (OAG) issued its report
alleging the Company has violated the CWR and recommended a $5 million penalty.
The Company filed its reply comments in July 2005. The Company and the OAG have
reached agreement on procedures to be followed for the current Cold Weather
Period beginning October 15, 2005. In addition, in June 2005, the Company was
named in a suit filed on behalf of a purported class of customers who allege
that the Company's conduct under the CWR was in violation of the Minnesota
Consumer Fraud Act and the Minnesota Deceptive Trade Practices Act and was
negligent and fraudulent. The Company believes that it has not knowingly and
intentionally violated the CWR and intends to vigorously contest the lawsuit.
The Company does not expect this matter to have a material adverse effect on its
financial condition, results of operations or cash flows.
(b) Environmental Matters.
Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are
among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish
and Bossier Parish, Louisiana. The suits allege that, at some
12
unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or
chemical contamination of the Wilcox Aquifer, which lies beneath property owned
or leased by certain of the defendants and which is the sole or primary drinking
water aquifer in the area. The primary source of the contamination is alleged by
the plaintiffs to be a gas processing facility in Haughton, Bossier Parish,
Louisiana known as the "Sligo Facility," which was formerly operated by a
predecessor in interest of CERC Corp. This facility was purportedly used for
gathering natural gas from surrounding wells, separating gasoline and
hydrocarbons from the natural gas for marketing, and transmission of natural gas
for distribution.
Beginning about 1985, the predecessors of certain CERC Corp. defendants
engaged in a voluntary remediation of any subsurface contamination of the
groundwater below the property they owned or leased. This work has been done in
conjunction with and under the direction of the Louisiana Department of
Environmental Quality. The plaintiffs seek monetary damages for alleged damage
to the aquifer underlying their property, unspecified alleged personal injuries,
alleged fear of cancer, alleged property damage or diminution of value of their
property, and, in addition, seek damages for trespass, punitive, and exemplary
damages. The Company does not expect the ultimate cost associated with resolving
this matter to have a material impact on the financial condition, results of
operations or cash flows of the Company.
Manufactured Gas Plant Sites. The Company and its predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, the Company has
completed remediation on two sites, other than ongoing monitoring and water
treatment. There are five remaining sites in the Company's Minnesota service
territory. The Company believes that it has no liability with respect to two of
these sites.
At September 30, 2005, the Company had accrued $18 million for remediation
of certain Minnesota sites. At September 30, 2005, the estimated range of
possible remediation costs for these sites was $7 million to $42 million based
on remediation continuing for 30 to 50 years. The cost estimates are based on
studies of a site or industry average costs for remediation of sites of similar
size. The actual remediation costs will be dependent upon the number of sites to
be remediated, the participation of other potentially responsible parties (PRP),
if any, and the remediation methods used. The Company has utilized an
environmental expense tracker mechanism in its rates in Minnesota to recover
estimated costs in excess of insurance recovery. As of September 30, 2005, the
Company has collected a total of $13 million from insurance companies and its
environmental tracker to be used for future environmental remediation.
In addition to the Minnesota sites, the United States Environmental
Protection Agency and other regulators have investigated MGP sites that were
owned or operated by the Company or may have been owned by one of its former
affiliates. The Company has been named as a defendant in two lawsuits under
which contribution is sought by private parties for the cost to remediate former
MGP sites based on the previous ownership of such sites by former affiliates of
the Company or its divisions. The Company has also been identified as a PRP by
the State of Maine for a site that is the subject of one of the lawsuits. In
March 2005, the court considering the other suit for contribution granted the
Company's motion to dismiss on the grounds that the Company was not an
"operator" of the site as had been alleged. The plaintiff in that case has filed
an appeal of the court's dismissal of the Company. The Company is investigating
details regarding these sites and the range of environmental expenditures for
potential remediation. However, the Company believes it is not liable as a
former owner or operator of those sites under the Comprehensive Environmental,
Response, Compensation and Liability Act of 1980, as amended, and applicable
state statutes, and is vigorously contesting those suits and its designation as
a PRP.
Mercury Contamination. The Company's pipeline and distribution operations
have in the past employed elemental mercury in measuring and regulating
equipment. It is possible that small amounts of mercury may have been spilled in
the course of normal maintenance and replacement operations and that these
spills may have contaminated the immediate area with elemental mercury. This
type of contamination has been found by the Company at some sites in the past,
and the Company has conducted remediation at these sites. It is possible that
other contaminated sites may exist and that remediation costs may be incurred
for these sites. Although the total amount of these costs cannot be known at
this time, based on experience by the Company and that of others in the natural
gas industry to date and on the current regulations regarding remediation of
these sites, the Company does not expect the costs of any remediation of these
sites to be material to the Company's financial condition, results of operations
or cash flows.
13
Other Environmental. From time to time the Company has received notices
from regulatory authorities or others regarding its status as a PRP in
connection with sites found to require remediation due to the presence of
environmental contaminants. In addition, the Company has been named from time to
time as a defendant in litigation related to such sites. Although the ultimate
outcome of such matters cannot be predicted at this time, the Company does not
expect, based on its experience to date, these matters, either individually or
in the aggregate, to have a material adverse effect on the Company's financial
condition, results of operations or cash flows.
(c) Other Proceedings.
The Company is involved in other legal, environmental, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding matters arising in the ordinary course of business. Some of
these proceedings involve substantial amounts. The Company's management
regularly analyzes current information and, as necessary, provides accruals for
probable liabilities on the eventual disposition of these matters. The Company's
management does not expect the disposition of these matters to have a material
adverse effect on the Company's financial condition, results of operations or
cash flows.
(10) REPORTABLE BUSINESS SEGMENTS
Because CERC Corp. is an indirect wholly owned subsidiary of CenterPoint
Energy, the Company's determination of reportable segments considers the
strategic operating units under which CenterPoint Energy manages sales,
allocates resources and assesses performance of various products and services to
wholesale or retail customers in differing regulatory environments.
The Company has identified the following reportable business segments:
Natural Gas Distribution, Pipelines and Gathering, and Other Operations. For
descriptions of the reportable business segments, see Note 12 to the CERC Corp.
10-K Notes, which is incorporated herein by reference.
The following tables summarize financial data for the Company's reportable
business segments:
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2004
---------------------------------------------
REVENUES FROM NET
EXTERNAL INTERSEGMENT OPERATING
CUSTOMERS REVENUES INCOME (LOSS)
------------- ------------ -------------
(IN MILLIONS)
Natural Gas Distribution .. $1,146 $ 3 $ (2)
Pipelines and Gathering ... 73 35 35
Other Operations .......... -- 1 (1)
Eliminations .............. -- (39) --
------ ---- ----
Consolidated .............. $1,219 $ -- $ 32
====== ==== ====
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005
---------------------------------------------
REVENUES FROM NET
EXTERNAL INTERSEGMENT OPERATING
CUSTOMERS REVENUES INCOME (LOSS)
------------- ------------ -------------
(IN MILLIONS)
Natural Gas Distribution .. $1,651 $ -- $(12)
Pipelines and Gathering ... 81 35 52
Other Operations .......... -- 2 --
Eliminations .............. -- (37) --
------ ---- ----
Consolidated .............. $1,732 $ -- $ 40
====== ==== ====
14
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004
--------------------------------------------------------------
REVENUES FROM NET TOTAL ASSETS AS
EXTERNAL INTERSEGMENT OPERATING OF DECEMBER 31,
CUSTOMERS REVENUES INCOME (LOSS) 2004
------------- ------------ ------------- ---------------
(IN MILLIONS)
Natural Gas Distribution............ $4,522 $ 3 $137 $4,798
Pipelines and Gathering............. 217 107 123 2,637
Other Operations.................... -- 6 (4) 792
Eliminations........................ -- (116) -- (694)
------ ----- ---- ------
Consolidated........................ $4,739 $ -- $256 $7,533
====== ===== ==== ======
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005
--------------------------------------------------------------
REVENUES FROM NET TOTAL ASSETS AS
EXTERNAL INTERSEGMENT OPERATING OF SEPTEMBER 30,
CUSTOMERS REVENUES INCOME (LOSS) 2005
------------- ------------ ------------- ---------------
(IN MILLIONS)
Natural Gas Distribution............ $5,408 $ 3 $ 146 $ 5,338
Pipelines and Gathering............. 252 110 168 2,925
Other Operations.................... 3 5 (3) 603
Eliminations........................ -- (118) -- (1,191)
------ ----- ----- -------
Consolidated........................ $5,663 $ -- $ 311 $ 7,675
====== ===== ===== =======
(11) EMPLOYEE BENEFIT PLANS
The Company's employees participate in CenterPoint Energy's postretirement
benefit plan. The Company's net periodic cost includes the following components
relating to postretirement benefits:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2004 2005 2004 2005
---- ---- ---- ----
(IN MILLIONS)
Service cost........................ $-- $-- $ 1 $ 1
Interest cost....................... 3 2 8 6
Expected return on plan assets...... -- -- (1) (1)
Net amortization.................... -- -- 1 1
Other ............................. -- 1 1 1
--- --- --- ---
Net periodic cost................ $ 3 $ 3 $10 $ 8
=== === === ===
The Company previously disclosed in its financial statements for the year
ended December 31, 2004, that it expected to contribute $16 million to its
postretirement benefits plan in 2005. As of September 30, 2005, $8 million has
been contributed.
15
ITEM 2. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS
The following narrative analysis should be read in combination with our
Interim Financial Statements contained in Item 1 of this report.
We are an indirect wholly owned subsidiary of CenterPoint Energy, Inc.
(CenterPoint Energy), a public utility holding company created on August 31,
2002, as part of a corporate restructuring of Reliant Energy, Incorporated
(Reliant Energy). CenterPoint Energy is a registered public utility holding
company under the Public Utility Holding Company Act of 1935, as amended (1935
Act). For information about the 1935 Act, please read " -- Liquidity -- Certain
Contractual and Regulatory Limits on Our Ability to Issue Securities, Borrow
Money and Pay Dividends."
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, 2004 and the three and nine months
ended September 30, 2005. Reference is made to "Management's Narrative Analysis
of the Results of Operations" in Item 7 of the Annual Report on Form 10-K of
CERC Corp. for the year ended December 31, 2004 (CERC Corp. Form 10-K).
REPEAL OF THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
On August 8, 2005, President Bush signed into law the Energy Policy Act of
2005 (Energy Act). Under that legislation, the 1935 Act is repealed effective
February 8, 2006. After the effective date of repeal, CenterPoint Energy and its
subsidiaries will no longer be subject to restrictions imposed under the 1935
Act. Until the repeal is effective, CenterPoint Energy and its subsidiaries
remain subject to the provisions of the 1935 Act and the terms of orders issued
by the Securities and Exchange Commission (SEC) under the 1935 Act. The Energy
Act grants to the Federal Energy Regulatory Commission (FERC) authority to
require holding companies and their subsidiaries to maintain certain books and
records and make them available for review by FERC and state regulatory
authorities. The Energy Act requires FERC to issue regulations to implement its
jurisdiction under the Energy Act, and on September 16, 2005, FERC issued
proposed rules for public comment. It is presently unknown what, if any,
specific obligations under those rules may be imposed on CenterPoint Energy and
its subsidiaries as a result of that rulemaking.
CONSOLIDATED RESULTS OF OPERATIONS
Our results of operations are affected by, among other things, seasonal
fluctuations in the demand for natural gas and price movements of energy
commodities, the actions of various federal, state and municipal 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 5 of Part II of this report
beginning on page 26 and "Management's Narrative Analysis of the Results of
Operations -- Certain Factors Affecting Future Earnings" in Item 7 of the CERC
Corp. Form 10-K, which is incorporated herein by reference.
16
The following table sets forth our consolidated results of operations for
the three and nine months ended September 30, 2004 and 2005, followed by a
discussion of our consolidated results of operations based on operating income.
We have provided a reconciliation of consolidated operating income to net income
below.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2004 2005 2004 2005
------ ------ ------ ------
(IN MILLIONS)
Revenues............................. $1,219 $1,732 $4,739 $5,663
------ ------ ------ ------
Expenses:
Natural gas....................... 928 1,422 3,701 4,563
Operation and maintenance......... 184 188 536 532
Depreciation and amortization..... 47 50 139 149
Taxes other than income taxes..... 28 32 107 108
------ ------ ------ ------
Total Expenses................. 1,187 1,692 4,483 5,352
------ ------ ------ ------
Operating Income..................... 32 40 256 311
Interest and Other Finance Charges... (45) (39) (134) (136)
Other Income, net.................... 4 6 10 18
------ ------ ------ ------
Income (Loss) Before Income Taxes.... (9) 7 132 193
Income Tax (Expense) Benefit......... 7 (3) (49) (66)
------ ------ ------ ------
Net Income (Loss).................... $ (2) $ 4 $ 83 $ 127
====== ====== ====== ======
THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2004
We reported net income of $4 million for the three months ended September
30, 2005 as compared to a net loss of $2 million for the same period in 2004.
The increase in net income of $6 million was primarily due to increased
operating income of $17 million in our Pipelines and Gathering business segment
offset by an increase in the operating loss in our Natural Gas Distribution
business segment of $10 million.
NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2004
We reported net income of $127 million for the nine months ended September
30, 2005 as compared to $83 million for the same period in 2004. The increase in
net income of $44 million was primarily due to increased operating income of $45
million in our Pipelines and Gathering business segment and increased operating
income of $9 million in our Natural Gas Distribution business segment. This
increase was partially offset by increased income tax expense of $17 million due
to higher pre-tax income, which was reduced by a favorable tax audit adjustment
recorded in the second quarter of 2005.
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
The following tables present operating income for our Natural Gas
Distribution and Pipelines and Gathering business segments for the three and
nine months ended September 30, 2004 and 2005. For information regarding factors
that may affect the future results of operations of our business segments,
please read "Risk Factors -- Principal Risk Factors Associated with Our
Businesses," " -- Risk Factors Associated with Our Consolidated Financial
Condition" and "-- Other Risks" in Item 5 of Part II of this report beginning on
page 26.
17
NATURAL GAS DISTRIBUTION
The following table provides summary data of our Natural Gas Distribution
business segment for the three and nine months ended September 30, 2004 and
2005:
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2004 2005 2004 2005
---------- ---------- ---------- ----------
(IN MILLIONS, EXCEPT CUSTOMER DATA)
Revenues .................................. $ 1,149 $ 1,651 $ 4,525 $ 5,411
---------- ---------- ---------- ----------
Expenses:
Natural gas ............................ 959 1,456 3,776 4,644
Operation and maintenance .............. 133 141 416 414
Depreciation and amortization .......... 36 39 106 116
Taxes other than income taxes .......... 23 27 90 91
---------- ---------- ---------- ----------
Total expenses ...................... 1,151 1,663 4,388 5,265
---------- ---------- ---------- ----------
Operating Income (Loss).................... $ (2) $ (12) $ 137 $ 146
========== ========== ========== ==========
Throughput (in billion cubic feet (Bcf)):
Residential ............................ 15 9 121 107
Commercial and industrial .............. 39 38 171 158
Non-rate regulated ..................... 113 160 419 491
Elimination (1) ........................ (32) (26) (105) (104)
---------- ---------- ---------- ----------
Total Throughput .................... 135 181 606 652
========== ========== ========== ==========
Average number of customers:
Residential ............................ 2,777,212 2,820,629 2,791,722 2,835,306
Commercial and industrial .............. 242,111 244,249 245,895 246,370
Non-rate regulated ..................... 6,249 6,515 6,234 6,520
---------- ---------- ---------- ----------
Total ............................... 3,025,572 3,071,393 3,043,851 3,088,196
========== ========== ========== ==========
- ----------
(1) Elimination of intrasegment sales.
THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2004
Our Natural Gas Distribution business segment reported an operating loss of
$12 million for the three months ended September 30, 2005 as compared to an
operating loss of $2 million for the same period in 2004. Increases in operating
income from rate increases ($3 million) and increased margins from our non-rate
regulated natural gas sales business ($11 million) were more than offset by the
impact of certain derivative transactions as discussed below ($8 million),
increases in operation and maintenance expenses ($8 million) primarily related
to higher bad debt expense ($5 million), increased depreciation expense
primarily due to higher plant balances ($3 million) and higher taxes other than
income taxes ($4 million).
A portion of CenterPoint Energy Services, Inc.'s (CES) activities include
entering into transactions for the physical purchase, transportation and sale of
natural gas at different locations (physical contracts). CES attempts to
mitigate basis risk associated with these activities by entering into financial
derivative contracts (financial contracts or financial basis swaps) to address
market price volatility between the purchase and sale delivery points that can
occur over the term of the physical contracts. The underlying physical contracts
are accounted for on an accrual basis with all associated earnings not
recognized until the time of actual physical delivery. The timing of the
earnings impacts for the financial contracts differs from the physical contracts
because the financial contracts meet the definition of a derivative under SFAS
No. 133, "Accounting for Derivative Instruments" (SFAS No. 133), and are
recorded at fair value as of each reporting balance sheet date with changes in
value reported through earnings. Changes in prices between the delivery points
(basis spreads) can and do vary daily resulting in changes to the fair value of
the financial contracts. However, the economic intent of the financial contracts
is to fix the actual net difference in the natural gas pricing at the different
locations for the associated physical purchase and sale contracts throughout the
life of the physical contracts and thus, when combined with the physical
contracts' terms, provide an expected fixed gross margin on the physical
contracts that will ultimately be recognized in earnings at the time of actual
delivery of the natural gas. As of September 30, 2005, the mark-to-market value
of the financial contracts described above reflected an unrealized loss of $3.6
million; however, the underlying expected fixed gross margin
18
associated with delivery under the physical contracts combined with the price
risk management provided through the financial contracts is $2.3 million. As
described above, over the term of these financial contracts, the quarterly
reported mark-to-market changes in value may vary significantly and the
associated unrealized gains and losses will be reflected in CES' earnings.
CES also sells physical gas and basis to its end-use customers who desire
to lock in a future spread between a specific location and Henry Hub (NYMEX). As
a result, CES incurs exposure to commodity basis risk related to these
transactions, which it attempts to mitigate by buying offsetting financial basis
swaps. Under SFAS No. 133, CES records at fair value and marks-to-market the
financial basis swaps as of each reporting balance sheet date with changes in
value reported through earnings. However, the associated physical sales
contracts are accounted for using the accrual basis, whereby earnings impacts
are not recognized until the time of actual physical delivery. Although the
timing of earnings recognition for the financial basis swaps differs from the
physical contracts, the economic intent of the financial basis swaps is to fix
the basis spread over the life of the physical contracts to an amount
substantially the same as the portion of the basis spread pricing included in
the physical contracts. In so doing, over the period that the financial basis
swaps and related physical contracts are outstanding, actual cumulative earnings
impacts for changes in the basis spread should be minimal, even though from a
timing perspective there could be fluctuations in unrealized gains or losses
associated with the changes in fair value recorded for the financial basis
swaps. The cumulative earnings impact from the financial basis swaps recognized
each reporting period is expected to be offset by the value realized when the
related physical sales occur. As of September 30, 2005, the mark-to-market value
of the financial basis swaps reflected an unrealized loss of $4.8 million.
NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2004
Our Natural Gas Distribution business segment reported operating income of
$146 million for the nine months ended September 30, 2005 as compared to $137
million for the same period in 2004. Increases in operating income from rate
increases ($19 million) and increased margins from our non-rate regulated
natural gas sales business ($13 million) were partially offset by the impact of
certain derivative transactions as discussed above ($8 million) and the impact
of milder weather and decreased throughput net of continued customer growth with
the addition of approximately 42,000 customers since September 2004 ($10
million). Operation and maintenance expense decreased $2 million. Excluding an
$8 million charge recorded in the first quarter of 2004 for severance costs
associated with staff reductions, operation and maintenance expenses increased
by $6 million primarily due to increased bad debt expense ($7 million),
partially offset by lower claims expense ($5 million) and the capitalization of
previously incurred restructuring expenses as allowed by a regulatory order from
the Railroad Commission of Texas ($5 million). Additionally, operating income
was unfavorably impacted by increased depreciation expense primarily due to
higher plant balances ($10 million).
During the third quarter of 2005, our east Texas, Louisiana and Mississippi
natural gas service areas were affected by Hurricanes Katrina and Rita. Damage
to our facilities was limited, but approximately 10,000 homes and businesses
were damaged to such an extent that they will not be taking service for the
foreseeable future. The impact on the Natural Gas Distribution business
segment's operating income was not material.
19
PIPELINES AND GATHERING
The following table provides summary data of our Pipelines and Gathering
business segment for the three and nine months ended September 30, 2004 and
2005:
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2004 2005 2004 2005
---- ---- ---- ----
(IN MILLIONS)
Revenues .......................... $108 $116 $324 $362
---- ---- ---- ----
Expenses:
Natural gas .................... 6 -- 33 25
Operation and maintenance ...... 52 47 122 121
Depreciation and amortization .. 11 12 33 34
Taxes other than income taxes .. 4 5 13 14
---- ---- ---- ----
Total expenses .............. 73 64 201 194
---- ---- ---- ----
Operating Income .................. $ 35 $ 52 $123 $168
==== ==== ==== ====
Throughput (in Bcf):
Natural Gas Sales .............. 1 -- 8 4
Transportation ................. 181 199 658 700
Gathering ...................... 79 92 233 262
Elimination (1) ................ -- (1) (5) (4)
---- ---- ---- ----
Total Throughput ............ 261 290 894 962
==== ==== ==== ====
- ----------
(1) Elimination of volumes both transported and sold.
THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2004
Our Pipelines and Gathering business segment reported operating income of
$52 million for the three months ended September 30, 2005 compared to $35
million for the same period in 2004. Operating margins (revenues less natural
gas costs) increased by $14 million primarily due to increased demand for
certain transportation and ancillary services ($13 million) and increased
throughput and demand for services related to our core gas gathering operations
($6 million), partially offset by reductions in project-related revenues ($6
million). Additionally, operation and maintenance expenses decreased by $5
million primarily due to a reduction in project-related expenses ($6 million),
offset by increased litigation costs ($4 million) recorded in the third quarter
of 2005.
NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2004
Our Pipelines and Gathering business segment reported operating income of
$168 million for the nine months ended September 30, 2005 compared to $123
million for the same period in 2004. Operating margins (revenues less natural
gas costs) increased by $46 million primarily due to increased demand for
certain transportation and ancillary services ($31 million), increased
throughput and demand for services related to our core gas gathering operations
($20 million), partially offset by reductions in project-related revenues ($10
million). Additionally, operation and maintenance expenses decreased by $1
million primarily due to a reduction in project-related expenses ($9 million),
offset by increased litigation costs ($4 million) recorded in the third quarter
of 2005.
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
For information on other developments, factors and trends that may have an
impact on our future earnings, please read "Management's Narrative Analysis of
Results of Operations -- Certain Factors Affecting Future Earnings" in Item 7 of
Part II of the CERC Corp. Form 10-K, which is incorporated herein by reference,
and "Risk Factors" in Item 5 of Part II of this report beginning on page 26.
LIQUIDITY
Our liquidity and capital requirements are affected primarily by our
results of operations, capital expenditures, debt service requirements, and
working capital needs. Our principal cash requirements for the last three months
of
20
2005 are approximately $145 million of capital expenditures. We expect that
borrowings under our credit facility, anticipated cash flows from operations and
borrowings from affiliates under the money pool described below will be
sufficient to meet our cash needs for 2005. Cash needs may also be met by
issuing securities in the capital markets.
The 1935 Act currently regulates our financing ability, as more fully
described in "--Certain Contractual and Regulatory Limits on Our Ability to
Issue Securities, Borrow Money and Pay Dividends" below.
On October 25, 2005, CenterPoint Energy Gas Transmission Company (CEGT), a
subsidiary of CERC Corp., executed a definitive Precedent Agreement with XTO
Energy Inc. (XTO) for CEGT to transport approximately 600 million cubic feet per
day of XTO's natural gas production for ten years. To fulfill the requirements
of the agreement, CEGT will construct a new 168-mile pipeline between Carthage,
Texas and its Perryville Hub in northeast Louisiana. The $375 million pipeline
will have an initial design capacity of approximately one Bcf per day. Pending
authorization by FERC, the pipeline could be in service as early as the winter
of 2006-2007. This agreement is expected to cause an increase in our estimated
capital requirements of approximately $5 million, $353 million and $17 million
in 2005, 2006 and 2007, respectively, for our Pipelines and Gathering business
segment from what was previously disclosed in the CERC Corp. Form 10-K.
Off-Balance Sheet Arrangements. Other than operating leases, we have no
off-balance sheet arrangements. However, we do participate in a receivables
factoring arrangement. We have a bankruptcy remote subsidiary, which we
consolidate, which was formed for the sole purpose of buying receivables created
by us and selling those receivables to an unrelated third-party. This
transaction is accounted for as a sale of receivables under the provisions of
SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities," and, as a result, the related receivables are
excluded from the Consolidated Balance Sheet. In January 2005, the $250 million
facility was extended to January 2006 and temporarily increased, for the period
from January 2005 to June 2005, to $375 million. As of September 30, 2005, we
had $141 million of advances under our receivables facility.
Credit Facilities. In June 2005, we replaced our $250 million three-year
revolving credit facility with a $400 million five-year revolving credit
facility. The new credit facility terminates on June 30, 2010. Borrowings under
this facility may be made at the London interbank offered rate (LIBOR) plus 55
basis points, including the facility fee, based on current credit ratings. An
additional utilization fee of 10 basis points applies to borrowings whenever
more than 50% of the facility is utilized. Changes in credit ratings could lower
or raise the increment to LIBOR depending on whether ratings improved or were
lowered.
Our $400 million credit facility contains covenants, including a total debt
to capitalization covenant of 65% and an earnings before interest, taxes,
depreciation and amortization (EBITDA) to interest covenant. Borrowings under
our $400 million credit facility are available notwithstanding that a material
adverse change has occurred or litigation that could be expected to have a
material adverse effect has occurred, so long as other customary terms and
conditions are satisfied.
As of November 1, 2005, our $400 million credit facility was not utilized.
Securities Registered with the SEC. At September 30, 2005, we had a shelf
registration statement covering $500 million principal of debt securities.
Temporary Investments. On September 30, 2005, we had temporary external
investments of $74 million. Our temporary external investments were reduced by
$325 million in July 2005 when the proceeds from the liquidation of such
investments were used to pay our maturing debt. As of November 1, 2005, we had
temporary external investments in a money market fund of $1.2 million. Such
investments may be utilized to meet our cash flow needs.
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 money pool's net funding requirements are generally met by
borrowings of CenterPoint Energy. The terms of the money pool are in accordance
with requirements currently applicable to registered public utility holding
companies under the 1935 Act and under an order from the SEC relating to our
financing activities dated June 29, 2005 (June 2005 Financing Order). Our money
pool borrowing limit under the existing order is $600 million. At November 1,
2005, we had no investments in or borrowings from the money pool. The money pool
may not provide sufficient funds to meet our cash needs.
21
Impact on Liquidity of a Downgrade in Credit Ratings. As of November 1,
2005, Moody's Investors Service, Inc. (Moody's), Standard & Poor's Ratings
Services, a division of The McGraw Hill Companies (S&P) and Fitch, Inc. (Fitch)
had assigned the following credit ratings to our senior unsecured debt:
MOODY'S S&P FITCH
- ------------------- ------------------- -------------------
RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3)
- ------ ---------- ------ ---------- ------ ----------
Baa3 Stable BBB Stable BBB Stable
- ----------
(1) A "stable" outlook from Moody's indicates that Moody's does not expect to
put the rating on review for an upgrade or downgrade within 18 months from
when the outlook was assigned or last affirmed.
(2) An S&P rating outlook assesses the potential direction of a long-term
credit rating over the intermediate to longer term.
(3) A "stable" outlook from Fitch encompasses a one-to-two year horizon as to
the likely ratings direction.
We cannot assure you that these 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, the
willingness of suppliers to extend credit lines to us on an unsecured basis and
the execution of our commercial strategies.
A decline in credit ratings could increase borrowing costs under our $400
million revolving credit facility. A decline in credit ratings would also
increase the interest rate on long-term debt to be issued in the capital markets
and would negatively impact our ability to complete capital market transactions
as more fully described in " -- Certain Contractual and Regulatory Limits on Our
Ability to Issue Securities, Borrow Money and Pay Dividends" below.
Additionally, a decline in credit ratings could increase cash collateral
requirements and reduce margins of our Natural Gas Distribution business
segment.
As described above under "-- Credit Facilities," our $400 million credit
facility does not contain a material adverse change clause with respect to
borrowings.
CES, one of our wholly owned subsidiaries, provides comprehensive natural
gas sales and services to industrial and commercial customers, electric
generators and natural gas utilities throughout the central United States. In
order to hedge its exposure to natural gas prices, CES has agreements with
provisions standard for the industry that establish credit thresholds and
require a party to provide additional collateral on two business days' notice
when that party's rating or the rating of a credit support provider for that
party (CERC Corp. in this case) falls below those levels. We estimate that as of
September 30, 2005, unsecured credit limits extended to CES by counterparties
could aggregate $115 million; however, utilized credit capacity is significantly
lower. In addition, we purchase natural gas under supply agreements that contain
an aggregate credit threshold of $100 million based on our S&P Senior Unsecured
Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will
increase and decrease the aggregate credit threshold accordingly.
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. Pursuant to the
indenture governing CenterPoint Energy's senior notes, 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. As of November 1, 2005, CenterPoint Energy had issued six series of
senior notes aggregating $1.4 billion in principal amount under this indenture.
A default by CenterPoint Energy would not trigger a default under our debt
instruments or bank credit facilities.
Other Factors that Could Affect Cash Requirements. In addition to the above
factors, our liquidity and capital resources could be affected by:
22
- - cash collateral requirements that could exist in connection with certain
contracts, including gas purchases, gas price hedging and gas storage
activities of our Natural Gas Distribution business segment, particularly
given gas price levels and volatility;
- - acceleration of payment dates on certain gas supply contracts under certain
circumstances as a result of increased gas prices and concentration of
suppliers;
- - increased costs related to the acquisition of gas;
- - increases in interest expense in connection with debt refinancings and
borrowings under our credit facility;
- - various regulatory actions;
- - slower customer payments and increased write-offs of receivables due to
higher gas prices;
- - restoration costs and revenues losses resulting from natural disasters such
as hurricanes; and
- - various of the risks identified in "Risk Factors" in Item 5 of Part II of
this report beginning on page 26.
Certain Contractual and Regulatory Limits on Our Ability to Issue
Securities, Borrow Money and Pay Dividends. Our bank facility and our
receivables facility limit our debt as a percentage of our total capitalization
to 65% and contain an EBITDA to interest covenant.
Our parent, CenterPoint Energy, is a registered public utility holding
company under the 1935 Act. The 1935 Act and related rules and regulations
impose a number of restrictions on our parent's activities and those of its
subsidiaries, including us. The 1935 Act, among other things, limits our
parent's ability and the ability of its regulated subsidiaries, including us, to
issue debt and equity securities without prior authorization, restricts the
source of dividend payments to current and retained earnings without prior
authorization, regulates sales and acquisitions of certain assets and businesses
and governs affiliated service, sales and construction contracts. On August 8,
2005, President Bush signed into law the Energy Act. Under that legislation, the
1935 Act is repealed effective February 8, 2006. After the effective date of
repeal, CenterPoint Energy and its subsidiaries will no longer be subject to
restrictions imposed under the 1935 Act. Until the repeal is effective,
CenterPoint Energy and its subsidiaries remain subject to the provisions of the
1935 Act and the terms of orders issued by the SEC under the 1935 Act. The
Energy Act grants to FERC authority to require holding companies and their
subsidiaries to maintain certain books and records and make them available for
review by FERC and state regulatory authorities. The Energy Act requires FERC to
issue regulations to implement its jurisdiction under the Energy Act, and on
September 16, 2005, FERC issued proposed rules for public comment. It is
presently unknown what, if any, specific obligations under those rules may be
imposed on CenterPoint Energy and its subsidiaries as a result of that
rulemaking.
The June 2005 Financing Order establishes limits on the amount of external
debt and equity securities that can be issued by CenterPoint Energy and its
regulated subsidiaries, including us, without additional authorization but
generally permits CenterPoint Energy to refinance its existing obligations and
those of its regulated subsidiaries, including us. We are in compliance with the
authorized limits. The order also generally permits utilization of our undrawn
credit facilities. Unless we obtain a further order from the SEC, as of October
31, 2005, we are authorized to issue an additional $367 million of debt or
preferred securities.
In the June 2005 Financing Order, the SEC "reserved jurisdiction" over a
number of matters, meaning that an order will be required from the SEC before we
may conduct those activities. However, an order regarding the activities over
which the SEC has reserved jurisdiction generally can be issued by the SEC more
quickly than orders on other matters, although there is no assurance that a
release of jurisdiction will be granted on a given matter or the terms under
which such an order may be issued. In the June 2005 Financing Order, the SEC
reserved jurisdiction over all authority otherwise granted if the common equity
level of CenterPoint Energy falls below its level as of March 31, 2005 (11.4%
net of securitization debt) or if the common equity ratio of either us or
CenterPoint Energy Houston Electric, LLC, another wholly owned subsidiary of
CenterPoint Energy, falls below 30%. Among the other transactions over which the
SEC reserved jurisdiction are: (i) issuance of securities by CenterPoint Energy
or any of its subsidiaries, including us, unless our and the issuer's other
securities which are rated have an investment grade rating from at least one
nationally recognized statistical rating organization, (ii) further investment
in inactive
23
subsidiaries and (iii) payment of dividends by us from capital or unearned
surplus. The June 2005 Financing Order also contains certain requirements for
interest rates, maturities, issuance expenses and use of proceeds in connection
with securities issued by us or any of our subsidiaries. So long as the common
equity of CenterPoint Energy is less than 30% of its capitalization, the SEC
also reserved jurisdiction over the use of proceeds from authorized financings
for the acquisition of additional energy-related or gas-related companies.
Finally, the SEC reserved jurisdiction over the issuance of $500 million in
incremental debt and preferred securities by us. The total authorized amount of
debt and preferred securities that could be outstanding during the authorization
period, including the amounts over which the SEC has reserved jurisdiction and
undrawn amounts under our revolving credit facility, is $3.256 billion. The
foregoing and the following restrictions contained in the June 2005 Financing
Order, along with other restrictions contained in that order, will cease to
apply to us on February 8, 2006.
The 1935 Act limits the payment of dividends to payment from current and
retained earnings unless specific authorization is obtained to pay dividends
from other sources. The June 2005 Financing Order also requires that we maintain
a ratio of common equity to total capitalization of 30%. At September 30, 2005,
our ratio was 57%.
Relationship with CenterPoint Energy. We are an indirect wholly owned
subsidiary of CenterPoint Energy. As a result of this relationship, the
financial condition and liquidity of our parent company could affect our access
to capital, our credit standing and our financial condition.
CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one that is both important to the
presentation of our financial condition and results of operations and requires
management to make difficult, subjective or complex accounting estimates. An
accounting estimate is an approximation made by management of a financial
statement element, item or account in the financial statements. Accounting
estimates in our historical consolidated financial statements measure the
effects of past business transactions or events, or the present status of an
asset or liability. The accounting estimates described below require us to make
assumptions about matters that are highly uncertain at the time the estimate is
made. Additionally, different estimates that we could have used or changes in an
accounting estimate that are reasonably likely to occur could have a material
impact on the presentation of our financial condition or results of operations.
The circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the effect of matters that are
inherently uncertain. Estimates and assumptions about future events and their
effects cannot be predicted with certainty. We base our estimates on historical
experience and on various other assumptions that we believe to be reasonable
under the circumstances, the results of which form the basis for making
judgments. These estimates may change as new events occur, as more experience is
acquired, as additional information is obtained and as our operating environment
changes. Our significant accounting policies are discussed in Note 2 to the
consolidated financial statements in the CERC Form 10-K (CERC 10-K Notes). We
believe the following accounting policies involve the application of critical
accounting estimates. Accordingly, these accounting estimates have been reviewed
and discussed with the audit committee of the board of directors of CenterPoint
Energy.
IMPAIRMENT OF LONG-LIVED ASSETS AND INTANGIBLES
We review the carrying value of our long-lived assets, including goodwill
and identifiable intangibles, whenever events or changes in circumstances
indicate that such carrying values may not be recoverable, and at least annually
for goodwill as required by SFAS No. 142, "Goodwill and Other Intangible Assets"
(SFAS No. 142). Unforeseen events and changes in circumstances and market
conditions and material differences in the value of long-lived assets and
intangibles due to changes in estimates of future cash flows, regulatory matters
and operating costs could negatively affect the fair value of our assets and
result in an impairment charge.
Fair value is the amount at which the asset could be bought or sold in a
current transaction between willing parties and may be estimated using a number
of techniques, including quoted market prices or valuations by third parties,
present value techniques based on estimates of cash flows, or multiples of
earnings or revenue performance measures. The fair value of the asset could be
different using different estimates and assumptions in these valuation
techniques.
24
We perform our goodwill impairment test at least annually and evaluate
goodwill when events or changes in circumstances indicate that the carrying
value of these assets may not be recoverable. Upon adoption of SFAS No. 142, we
initially selected January 1 as our annual goodwill impairment testing date.
Since the time we selected the January 1 date, our year-end closing and
reporting process has been truncated in order to meet the accelerated periodic
reporting requirements of the SEC resulting in significant constraints on our
human resources at year-end and during our first fiscal quarter. Accordingly, in
order to meet the accelerated reporting deadlines and to provide adequate time
to complete the analysis each year, beginning in the third quarter of 2005, we
changed the date on which we perform our annual goodwill impairment test from
January 1 to July 1. We believe the July 1 alternative date will alleviate the
resource constraints that exist during the first quarter and allow us to utilize
additional resources in conducting the annual impairment evaluation of goodwill.
We performed the test at July 1, 2005, and determined that no impairment charge
for goodwill was required. The change is not intended to delay, accelerate or
avoid an impairment charge. We believe that this accounting change is an
alternative accounting principle that is preferable under the circumstances.
UNBILLED REVENUES
Revenues related to the sale and/or delivery of natural gas are generally
recorded when natural gas is delivered to customers. However, the determination
of sales to individual customers is based on the reading of their meters, which
is performed on a systematic basis throughout the month. At the end of each
month, amounts of natural gas delivered to customers since the date of the last
meter reading are estimated and the corresponding unbilled revenue is estimated.
Unbilled natural gas sales are estimated based on estimated purchased gas
volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As
additional information becomes available, or actual amounts are determinable,
the recorded estimates are revised. Consequently, operating results can be
affected by revisions to prior accounting estimates.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 2 to the Interim Financial Statements for a discussion of new
accounting pronouncements that affect us.
ITEM 4. CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our principal executive officer and principal financial officer, of
the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our principal executive
officer and principal financial officer concluded that our disclosure controls
and procedures were effective as of September 30, 2005 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.
There has been no change in our internal controls over financial reporting
that occurred during the three months ended September 30, 2005 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.
25
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For a description of certain legal and regulatory proceedings affecting us,
please review Notes 3 and 9 to our Interim Financial Statements, "Business --
Regulation" and " -- Environmental Matters" in Item 1 of the CERC Corp. Form
10-K, "Legal Proceedings" in Item 3 of the CERC Corp. Form 10-K and Notes 3,
9(c) and (d) to the CERC Corp. 10-K Notes, each of which is incorporated herein
by reference.
ITEM 5. OTHER INFORMATION
RISK FACTORS
PRINCIPAL RISK FACTORS ASSOCIATED WITH OUR BUSINESSES
RATE REGULATION OF OUR BUSINESS MAY DELAY OR DENY OUR ABILITY TO EARN A
REASONABLE RETURN AND FULLY RECOVER OUR COSTS.
Our rates for our local distribution companies are regulated by certain
municipalities and state commissions 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 ALTERNATIVE ENERGY SOURCES, WHICH COULD LEAD TO
LESS NATURAL GAS BEING MARKETED, AND OUR PIPELINES AND GATHERING BUSINESSES MUST
COMPETE DIRECTLY WITH OTHERS IN THE TRANSPORTATION, STORAGE, GATHERING, TREATING
AND PROCESSING OF NATURAL GAS, WHICH COULD LEAD TO LOWER PRICES, EITHER OR 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 we market, sell or transport 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. They 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.
OUR NATURAL GAS DISTRIBUTION BUSINESS IS SUBJECT TO FLUCTUATIONS IN NATURAL GAS
PRICING LEVELS, WHICH COULD AFFECT THE ABILITY OF OUR SUPPLIERS AND CUSTOMERS TO
MEET THEIR OBLIGATIONS.
We are subject to risk associated with price movements of natural gas.
Movements in natural gas prices might affect our ability to collect balances due
from our customers and, on the regulated side, 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
apply downward demand pressure on natural gas consumption in the areas in which
we operate and increase the risk that our suppliers or customers fail or are
unable to meet their obligations. Additionally, increasing gas prices could
create the need for us to provide collateral in order to purchase gas.
26
IF WE WERE TO FAIL TO EXTEND A CONTRACT WITH ONE OF OUR SIGNIFICANT PIPELINE
CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON OUR OPERATIONS.
Our contract with Laclede Gas Company, one of our pipeline's customers, is
currently scheduled to expire in 2007. To the extent the pipeline is unable to
extend this contract or the contract is renegotiated at rates substantially less
than the rates provided in the current contract, there could be an adverse
effect on our results of operations, financial condition and cash flows.
A DECLINE IN OUR CREDIT RATING COULD RESULT IN US HAVING TO PROVIDE COLLATERAL
IN ORDER TO PURCHASE GAS.
If our credit rating were to decline, we might be required to post cash
collateral in order to purchase natural gas. If a credit rating downgrade and
the resultant cash collateral requirement were to occur at a time when we were
experiencing significant working capital requirements or otherwise lacked
liquidity, we might be unable to obtain the necessary natural gas to meet our
contractual distribution obligations, and our results of operations, financial
condition and cash flows would be adversely affected.
OUR INTERSTATE PIPELINES' AND NATURAL GAS GATHERING AND PROCESSING BUSINESS'
REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF
GAS.
Our interstate pipelines and natural gas gathering and processing business
largely rely on gas sourced in the various supply basins located in the
Midcontinent region of the United States. 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 AND RESULTS OF OPERATIONS ARE SEASONAL.
A substantial portion of our revenues are 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.
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, 2005, we had $2.0 billion of outstanding indebtedness.
As of September 30, 2005, approximately $152 million principal amount of this
debt must be paid through 2006. The success of our future financing efforts may
depend, at least in part, on:
- general economic and capital market conditions;
- credit availability from financial institutions and other lenders;
- investor confidence in us and the markets in which we operate;
- maintenance of acceptable credit ratings by us and by CenterPoint
Energy;
- market expectations regarding our future earnings and probable cash
flows;
- market perceptions of our ability to access capital markets on
reasonable terms;
- provisions of relevant tax and securities laws; and
- our ability to obtain approval of specific financing transactions
under the 1935 Act prior to the effective date of the repeal of the
1935 Act.
27
Our current credit ratings are discussed in "Management's Narrative
Analysis of the Results of Operations -- Liquidity -- Impact on Liquidity of a
Downgrade in Credit Ratings" in Item 2 of Part I of this report. These credit
ratings may not remain in effect for any given period of time and one or more of
these ratings may be lowered or withdrawn entirely by a rating agency. We note
that these credit ratings are not recommendations to buy, sell or hold our
securities. Each rating should be evaluated independently of any other rating.
Any future reduction or withdrawal of one or more of our credit ratings could
have a material adverse impact on our ability to access capital on acceptable
terms.
THE FINANCIAL CONDITION AND LIQUIDITY OF OUR PARENT COMPANY COULD AFFECT OUR
ACCESS TO CAPITAL, OUR CREDIT STANDING AND OUR FINANCIAL CONDITION.
Our ratings and credit may be impacted by CenterPoint Energy's credit
standing. As of September 30, 2005, CenterPoint Energy and its subsidiaries
other than us have approximately $1.3 billion principal amount of debt required
to be paid through 2006. This amount excludes amounts related to capital leases,
securitization debt and indexed debt securities obligations. CenterPoint Energy
and its other subsidiaries may not be able to pay or refinance these amounts. If
CenterPoint Energy were to experience a deterioration in its credit standing or
liquidity difficulties, our access to credit and our credit ratings could be
adversely affected.
WE ARE AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY. CENTERPOINT
ENERGY CAN EXERCISE SUBSTANTIAL CONTROL OVER OUR DIVIDEND POLICY AND BUSINESS
AND OPERATIONS AND COULD DO SO IN A MANNER THAT IS ADVERSE TO OUR INTERESTS.
We are managed by officers and employees of CenterPoint Energy. Our
management will make determinations with respect to the following:
- our payment of dividends;
- decisions on our financings and our capital raising activities;
- mergers or other business combinations; and
- our acquisition or disposition of assets.
There are no contractual restrictions on our ability to pay dividends to
CenterPoint Energy. Our management could decide to increase our dividends to
CenterPoint Energy to support its cash needs. This could adversely affect our
liquidity. Under the 1935 Act, our ability to pay dividends is restricted by the
SEC's requirement that common equity as a percentage of total capitalization
must be at least 30% after the payment of any dividend. 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 NEGATIVELY IMPACT OUR RESULTS
OF OPERATIONS AND THOSE OF OUR SUBSIDIARIES.
We use derivative instruments, such as swaps, options, futures and
forwards, to manage our commodity and financial market risks. We could recognize
financial losses as a result of volatility in the market values of these
contracts, or if a counterparty fails 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.
OTHER RISKS
WE, AS A SUBSIDIARY OF CENTERPOINT ENERGY, A HOLDING COMPANY, ARE SUBJECT TO
REGULATION UNDER THE 1935 ACT. THE 1935 ACT AND RELATED RULES AND REGULATIONS
IMPOSE A NUMBER OF RESTRICTIONS ON OUR ACTIVITIES.
CenterPoint Energy and its subsidiaries, including us, are subject to
regulation by the SEC under the 1935 Act. The 1935 Act, among other things,
limits the ability of a holding company and its regulated subsidiaries to issue
28
debt and equity securities without prior authorization, restricts the source of
dividend payments to current and retained earnings without prior authorization,
regulates sales and acquisitions of certain assets and businesses and governs
affiliated service, sales and construction contracts.
CenterPoint Energy received an order from the SEC under the 1935 Act on
June 29, 2005 relating to its financing activities, which is effective until
June 30, 2008. Unforeseen events could result in capital needs in excess of
currently authorized amounts, necessitating further authorization from the SEC.
Approval of filings under the 1935 Act can take extended periods.
The Energy Policy Act of 2005 repeals the 1935 Act effective in 2006. We
cannot predict at this time the effect of the repeal on our business.
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.
ITEM 6. EXHIBITS
The following exhibits are filed herewith:
Exhibits not incorporated by reference to a prior filing are designated by
a cross (+); all exhibits not so designated are incorporated by reference to a
prior filing as indicated.
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
- ------- ------------------------------------------------ ------------------------------------- ------------ ---------
3.1.1 - Certificate of Incorporation of RERC Corp. Form 10-K for the year ended December 1-13265 3(a)(1)
31, 1997
3.1.2 - Certificate of Merger merging former NorAm Form 10-K for the year ended December 1-13265 3(a)(2)
Energy Corp. with and into HI Merger, Inc. 31, 1997
dated August 6, 1997
3.1.3 - Certificate of Amendment changing the name Form 10-K for the year ended December 1-13265 3(a)(3)
to Reliant Energy Resources Corp. 31, 1998
3.1.4 - Certificate of Amendment changing the name Form 10-Q for the quarter ended June 1-13265 3(a)(4)
to CenterPoint Energy Resources Corp. 30, 2003
3.2 - Bylaws of RERC Corp. Form 10-K for the year ended December 1-13265 3(b)
31, 1997
4.1 - $400,000,000 Credit Agreement, dated as of Form 8-K dated June 29, 2005 1-13265 4.1
June 30, 2005, among CERC Corp., as
Borrower, and the Initial Lenders named
therein, as Initial Lenders
+18.1 - Preferability Letter re: Change in
Accounting Principle
+31.1 - Rule 13a-14(a)/15d-14(a) Certification of
David M. McClanahan
+31.2 - Rule 13a-14(a)/15d-14(a) Certification of
Gary L. Whitlock
29
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
- ------- ------------------------------------------------ ------------------------------------- ------------ ---------
+32.1 - Section 1350 Certification of David M.
McClanahan
+32.2 - Section 1350 Certification of Gary L.
Whitlock
+99.1 - Items incorporated by reference from the
CERC Corp. Form 10-K. Item 1 "Business--
Regulation" and "-- Environmental Matters,"
Item 3 "Legal Proceedings" and Item 7
"Management's Narrative Analysis of the
Results of Operations-- Certain Factors
Affecting Future Earnings" and Notes 2(e)
(Regulatory Assets and Liabilities), 3
(Regulatory Matters), 5 (Derivative
Instruments), 9 (Commitments and
Contingencies) and 12 (Reportable Business
Segments).
30
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/ James S. Brian
------------------------------------
James S. Brian
Senior Vice President and Chief
Accounting Officer
Date: November 9, 2005
31
EXHIBIT INDEX
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.
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
- ------- ------------------------------------------------ ------------------------------------- ------------ ---------
3.1.1 - Certificate of Incorporation of RERC Corp. Form 10-K for the year ended December 1-13265 3(a)(1)
31, 1997
3.1.2 - Certificate of Merger merging former NorAm Form 10-K for the year ended December 1-13265 3(a)(2)
Energy Corp. with and into HI Merger, Inc. 31, 1997
dated August 6, 1997
3.1.3 - Certificate of Amendment changing the name Form 10-K for the year ended December 1-13265 3(a)(3)
to Reliant Energy Resources Corp. 31, 1998
3.1.4 - Certificate of Amendment changing the name Form 10-Q for the quarter ended June 1-13265 3(a)(4)
to CenterPoint Energy Resources Corp. 30, 2003
3.2 - Bylaws of RERC Corp. Form 10-K for the year ended December 1-13265 3(b)
31, 1997
4.1 - $400,000,000 Credit Agreement, dated as of Form 8-K dated June 29, 2005 1-13265 4.1
June 30, 2005, among CERC Corp., as
Borrower, and the Initial Lenders named
therein, as Initial Lenders
+18.1 - Preferability Letter re: Change in
Accounting Principle
+31.1 - Rule 13a-14(a)/15d-14(a) Certification of
David M. McClanahan
+31.2 - Rule 13a-14(a)/15d-14(a) Certification of
Gary L. Whitlock
+32.1 - Section 1350 Certification of David M.
McClanahan
+32.2 - Section 1350 Certification of Gary L.
Whitlock
+99.1 - Items incorporated by reference from the
CERC Corp. Form 10-K. Item 1 "Business--
Regulation" and "-- Environmental Matters,"
Item 3 "Legal Proceedings" and Item 7
"Management's Narrative Analysis of the
Results of Operations-- Certain Factors
Affecting Future Earnings" and Notes 2(e)
(Regulatory Assets and Liabilities), 3
(Regulatory Matters), 5 (Derivative
Instruments), 9 (Commitments and
Contingencies) and 12 (Reportable Business
Segments).