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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
AMENDMENT NO. 2
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM __________ TO __________
COMMISSION FILE NUMBER 1-13265
CENTERPOINT ENERGY RESOURCES CORP.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0511406
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1111 LOUISIANA
HOUSTON, TEXAS 77002 (713) 207-1111
(Address and zip code of principal (Registrant's telephone number,
executive offices) including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
NorAm Financing I 6 1/4% Convertible Trust New York Stock Exchange
Originated Preferred Securities
6% Convertible Subordinated Debentures due New York Stock Exchange
2012
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
NONE
CENTERPOINT ENERGY RESOURCES CORP. MEETS THE CONDITIONS SET FORTH IN
GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS
FORM 10-K WITH THE REDUCED DISCLOSURE FORMAT.
Indicate by check mark 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 if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the 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]
The aggregate market value of the common equity held by non-affiliates as
of June 30, 2004: None
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EXPLANATORY NOTE
CenterPoint Energy Resources Corp. (CERC Corp. or the Company) hereby
amends Items 7, 8 and 9A of Part II and Item 15 of Part IV of its Annual Report
on Form 10-K for the year ended December 31, 2004 filed on March 24, 2005 (Form
10-K), as amended by Amendment No. 1 thereto on Form 10-K/A filed on August 29,
2005 (Amendment No. 1), to reflect the restatement of the Company's consolidated
financial statements as discussed in Note 13. Amendment No. 1 was filed solely
for the purpose of supplementing the Form 10-K by filing the opinion of the
Company's independent registered public accounting firm regarding the financial
statement schedules contained in Item 15 that was inadvertently omitted from the
Form 10-K. Contemporaneously with the filing of this Amendment No. 2 to the Form
10-K on this Form 10-K/A, CERC Corp. is filing amendments to its Quarterly
Reports on Forms 10-Q/A for each of the first three quarters of 2005.
For purposes of this Form 10-K/A, and in accordance with Rule 12b-15 under
the Securities Exchange Act of 1934, as amended, each item of the Form 10-K, as
amended by Amendment No. 1, that was affected by the restatement has been
amended to the extent affected and restated in its entirety. NO ATTEMPT HAS BEEN
MADE IN THIS FORM 10-K/A TO UPDATE OTHER DISCLOSURES AS PRESENTED IN THE FORM
10-K, AS AMENDED BY AMENDMENT NO. 1, EXCEPT AS REQUIRED TO REFLECT THE EFFECTS
OF THE RESTATEMENT. ACCORDINGLY, THIS FORM 10-K/A SHOULD BE READ IN CONJUNCTION
WITH THE COMPANY'S SEC FILINGS MADE SUBSEQUENT TO THE FILING OF THE FORM 10-K,
INCLUDING ANY AMENDMENTS OF THOSE FILINGS. IN ADDITION, THIS FORM 10-K/A
INCLUDES UPDATED CERTIFICATIONS FROM THE COMPANY'S CEO AND CFO AS EXHIBITS 31.1,
31.2, 32.1 AND 32.2.
i
TABLE OF CONTENTS
PAGE
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PART II
Item 7. Management's Narrative Analysis of Results of Operations...... 1
Item 8. Financial Statements and Supplementary Data................... 10
Item 9A. Controls and Procedures....................................... 37
PART IV
Item 15. Exhibits and Financial Statement Schedules.................... 38
ii
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
From time to time we make statements concerning our expectations, beliefs,
plans, objectives, goals, strategies, future events or performance and
underlying assumptions and other statements that are not historical facts. These
statements are "forward-looking statements" within the meaning of the Private
Securities Litigation Reform Act of 1995. Actual results may differ materially
from those expressed or implied by these statements. You can generally identify
our forward-looking statements by the words "anticipate," "believe," "continue,"
"could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective,"
"plan," "potential," "predict," "projection," "should," "will," or other similar
words.
We have based our forward-looking statements on our management's beliefs
and assumptions based on information available to our management at the time the
statements are made. We caution you that assumptions, beliefs, expectations,
intentions and projections about future events may and often do vary materially
from actual results. Therefore, we cannot assure you that actual results will
not differ materially from those expressed or implied by our forward-looking
statements.
Some of the factors that could cause actual results to differ from those
expressed or implied by our forward-looking statements are described under "Risk
Factors" beginning on page 11 in Item 1 of our Annual Report on Form 10-K for
the year ended December 31, 2004 filed on March 24, 2005.
You should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular
statement, and we undertake no obligation to publicly update or revise any
forward-looking statements.
iii
PART II
ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
The following narrative analysis should be read in combination with our
consolidated financial statements and notes contained in Item 8 of this report.
RESTATEMENT
The following management narrative analysis gives effect to the restatement
discussed in Note 13 to our consolidated financial statements.
BACKGROUND
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). Our operating subsidiaries own and operate natural gas
distribution facilities, interstate pipelines and natural gas gathering,
processing and treating facilities.
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 Ability to Issue Securities and Pay
Dividends."
BUSINESS SEGMENTS
Because we are an indirect wholly owned subsidiary of CenterPoint Energy,
our determination of reportable segments considers the strategic operating units
under which CenterPoint Energy manages sales, allocates resources and assesses
performance of various products and services to wholesale or retail customers in
differing regulatory environments. We have identified the following reportable
business segments: Natural Gas Distribution, Pipelines and Gathering and Other
Operations.
NATURAL GAS DISTRIBUTION
Our natural gas distribution business engages in intrastate natural gas
sales to, and natural gas transportation for, approximately 3 million
residential, commercial and industrial customers in Arkansas, Louisiana,
Minnesota, Mississippi, Oklahoma and Texas. These operations are regulated as
natural gas utility operations. Our operations also include non-rate regulated
retail and wholesale gas sales to, and transportation services for, commercial
and industrial customers in the six states listed above as well as several other
Midwestern states.
PIPELINES AND GATHERING
Our pipelines and gathering business operates two interstate natural gas
pipelines as well as gas gathering facilities and also provides pipeline
services. Our gathering operations are conducted by a wholly owned gas gathering
subsidiary, CenterPoint Energy Field Services, Inc. (CEFS). CEFS is a natural
gas gathering and processing business serving natural gas fields in the
Midcontinent basin of the United States that interconnect with our pipelines, as
well as other interstate and intrastate pipelines. CEFS operates gathering
pipelines, which collect natural gas from approximately 200 separate systems
located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.
CEFS, through its Service Star operating division, provides remote data
monitoring and communications services to affiliates and third parties. The
Service Star operating division provides monitoring activities at over 6,000
locations across Alabama, Arkansas, Kansas, Louisiana, Mississippi, Missouri,
New Mexico, Oklahoma, Texas and Wyoming.
OTHER OPERATIONS
Our Other Operations business segment includes unallocated corporate costs
and inter-segment eliminations.
1
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
Our past earnings and results of operations are not necessarily indicative
of our future earnings and results of operations. The magnitude of our future
earnings and results of our operations will depend on or be affected by numerous
factors including:
- state and federal legislative and regulatory actions or developments,
constraints placed on our activities or business by the 1935 Act,
changes in or application of laws or regulations applicable to other
aspects of our business;
- 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;
- 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;
- our internal restructuring or other restructuring options that may be
pursued;
- our potential business strategies, including acquisitions or
dispositions of assets or businesses, which cannot be assured to be
completed or beneficial to us; and
- other factors discussed under "Risk Factors" in Item 1 of our Annual
Report on Form 10-K for the year ended December 31, 2004 filed on
March 24, 2005 (CERC Corp. Form 10-K).
CONSOLIDATED RESULTS OF OPERATIONS
Our results of operations are affected by seasonal fluctuations in the
demand for natural gas and price movements of energy commodities. Our results of
operations are also affected by, among other things, the actions of various
federal and state governmental authorities having jurisdiction over rates we
charge, competition in our various business operations, debt service costs and
income tax expense.
The following table sets forth selected financial data for the years ended
December 31, 2002, 2003 and 2004, 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.
2
YEAR ENDED DECEMBER 31,
------------------------
2002 2003 2004
------ ------ ------
(IN MILLIONS)
Revenues ............................ $4,208 $5,650 $6,472
------ ------ ------
Expenses:
Natural gas ...................... 2,901 4,297 5,013
Operation and maintenance ........ 667 688 732
Depreciation and amortization .... 167 176 187
Taxes other than income taxes .... 120 130 147
------ ------ ------
Total ......................... 3,855 5,291 6,079
------ ------ ------
Operating Income .................... 353 359 393
Interest and other finance charges .. (153) (179) (178)
Other income, net ................... 8 8 16
------ ------ ------
Income Before Income Taxes .......... 208 188 231
Income Tax Expense .................. (88) (59) (87)
------ ------ ------
Net Income .................... $ 120 $ 129 $ 144
====== ====== ======
2004 Compared to 2003. We reported net income of $144 million for 2004 as
compared to $129 million for 2003. The increase in net income of $15 million was
primarily due to increased operating income of $20 million in our Natural Gas
Distribution business segment, primarily due to rate increases, and increased
operating income of $22 million in our Pipelines and Gathering business segment,
primarily from increased throughput, favorable commodity prices and increased
ancillary services.
Our effective tax rate for 2004 and 2003 was 37.5% and 31.3%, respectively.
The increase in the effective rate for 2004 compared to 2003 was primarily the
result of a non-recurring decreased tax expense in 2003 relating to our
Minnesota operations.
2003 Compared to 2002. We reported net income of $129 million for 2003 as
compared to $120 million for 2002. The increase in net income of $9 million was
primarily due to increased operating income of $4 million in our Natural Gas
Distribution business segment, primarily due to rate increases, and increased
operating income of $5 million in our Pipelines and Gathering business segment,
primarily from favorable commodity prices and increased ancillary services.
Our effective tax rate for 2003 and 2002 was 31.3% and 42.2%, respectively.
The decrease in the effective rate for 2003 compared to 2002 was primarily the
result of a non-recurring decreased tax expense in 2003 relating to our
Minnesota operations.
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
The following tables present operating income for our Natural Gas
Distribution and Pipelines and Gathering business segments for 2002, 2003 and
2004. Some amounts from the previous years have been reclassified to conform to
the 2004 presentation of the financial statements. These reclassifications do
not affect consolidated net income.
3
NATURAL GAS DISTRIBUTION
The following table provides summary data of our Natural Gas Distribution
business segment for 2002, 2003 and 2004 (in millions):
YEAR ENDED DECEMBER 31,
------------------------
2002 2003 2004
------ ------ ------
Operating Revenues ................ $3,960 $5,435 $6,173
------ ------ ------
Operating Expenses:
Natural gas .................... 2,995 4,428 5,120
Operation and maintenance ...... 539 560 566
Depreciation and amortization .. 126 136 143
Taxes other than income taxes .. 102 109 122
------ ------ ------
Total operating expenses .... 3,762 5,233 5,951
------ ------ ------
Operating Income .................. $ 198 $ 202 $ 222
====== ====== ======
2004 Compared to 2003. Our Natural Gas Distribution business segment
reported operating income of $222 million for 2004 as compared to $202 million
for 2003. Increases in operating income of $4 million from continued customer
growth with the addition of 45,000 customers since December 31, 2003, $15
million from rate increases, $11 million from the impact of the 2003 change in
estimate of margins earned on unbilled revenues implemented in 2003 and $9
million related to certain regulatory adjustments made to the amount of
recoverable gas costs in 2003 were partially offset by the $8 million impact of
milder weather. Operations and maintenance expense increased $6 million for 2004
as compared to 2003. Excluding an $8 million charge recorded in the first
quarter of 2004 for severance costs associated with staff reductions, which has
reduced costs in later periods, operation and maintenance expenses decreased by
$2 million.
2003 Compared to 2002. Our Natural Gas Distribution business segment's
operating income increased $4 million in 2003 compared to 2002 primarily due to
higher revenues from rate increases implemented late in 2002 ($33 million),
improved margins from our unregulated commercial and industrial sales ($6
million) and continued customer growth with the addition of over 38,000
customers since December 2002 ($6 million). These increases were partially
offset by decreased revenues as a result of a decrease in the estimate of
margins earned on unbilled revenues ($11 million). Additionally, operating
income was negatively impacted by higher employee benefit expenses primarily due
to increased pension costs ($13 million), certain costs being included in
operating expense subsequent to the amendment of a receivables facility in
November 2002 as compared to being included in interest expense in the prior
year ($7 million) and increased bad debt expense primarily due to higher gas
prices ($9 million).
PIPELINES AND GATHERING
The following table provides summary data of our Pipelines and Gathering
business segment for 2002, 2003 and 2004 (in millions):
YEAR ENDED DECEMBER 31,
-----------------------
2002 2003 2004
---- ---- ----
Operating Revenues ................ $374 $407 $451
---- ---- ----
Operating Expenses:
Natural gas .................... 32 61 46
Operation and maintenance ...... 130 129 164
Depreciation and amortization .. 41 40 44
Taxes other than income taxes .. 18 19 17
---- ---- ----
Total operating expenses .... 221 249 271
---- ---- ----
Operating Income .................. $153 $158 $180
==== ==== ====
2004 Compared to 2003. Our Pipelines and Gathering business segment's
operating income increased by $22 million in 2004 compared to 2003. Operating
margins (revenues less fuel costs) increased by $59 million primarily due to
favorable commodity pricing ($3 million), increased demand for certain
transportation services driven by commodity price volatility ($36 million) and
increased throughput and enhanced services related to our core gas gathering
operations ($11 million). The increase in operating margin was partially offset
by higher operation and maintenance expenses of $35 million primarily due to
compliance with pipeline integrity regulations ($4 million)
4
and costs relating to environmental matters ($9 million). Project work expenses
included in operation and maintenance expense increased ($11 million) resulting
in a corresponding increase in revenues billed for these services ($15 million).
2003 Compared to 2002. Our Pipelines and Gathering business segment's
operating income increased $5 million in 2003 compared to 2002. The increase was
primarily a result of increased margins (revenues less fuel costs) due to higher
commodity prices ($8 million), improved margins from new transportation
contracts to power plants ($7 million) and improved margins from enhanced
services in our gas gathering operations ($4 million), partially offset by
higher pension, employee benefit and other miscellaneous expenses ($14 million).
Project work expenses included in operation and maintenance expense decreased
($15 million) resulting in a corresponding decrease in revenues billed for these
services ($14 million).
FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS
For information regarding our exposure to risk as a result of fluctuations
in commodity prices and derivative instruments, please read "Quantitative and
Qualitative Disclosures About Market Risk" in Item 7A of the CERC Form 10-K.
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 during 2005 are
approximately $357 million of capital expenditures and $361 million principal
amount of maturing debt. We expect that borrowings under our credit facility,
anticipated cash flows from operations and borrowings from affiliates will be
sufficient to meet our cash needs for 2005.
The 1935 Act regulates our financing ability, as more fully described in
"--Certain Contractual and Regulatory Limits on Ability to Issue Securities and
Pay Dividends" below.
Capital Requirements. We anticipate investing up to an aggregate $1.6
billion in capital expenditures in the years 2005 through 2009. The following
table sets forth our capital expenditures for 2004 and estimates of our capital
requirements for 2005 through 2009 (in millions):
2004... $269
2005... 357
2006... 343
2007... 281
2008... 260
2009... 312
The following table sets forth estimates of our contractual obligations to
make future payments for 2005 through 2009 and thereafter (in millions):
2010 AND
CONTRACTUAL OBLIGATIONS(1) TOTAL 2005 2006 2007 2008 2009 THEREAFTER
-------------------------- ------ ------ ---- ---- ---- ---- ----------
Long-term debt, including current portion(2) .. $2,368 $ 367 $158 $ 7 $307 $ 7 $1,522
Operating leases(3) ........................... 91 20 16 12 11 6 26
Non-trading derivative liabilities ............ 33 26 -- 4 2 1 --
Other commodity commitments(4) ................ 1,432 807 401 193 29 1 1
------ ------ ---- ---- ---- --- ------
Total contractual cash obligations ......... $3,924 $1,220 $575 $216 $349 $15 $1,549
====== ====== ==== ==== ==== === ======
- ----------
(1) We expect to contribute approximately $16 million to our postretirement
benefits plan in 2005 to fund a portion of our obligations in accordance
with rate orders or to fund pay-as-you-go costs associated with the plan.
(2) The amounts reflected for long-term debt obligations in the table above do
not include interest.
5
(3) For a discussion of operating leases, please read Note 9(b) to our
consolidated financial statements.
(4) For a discussion of other commodity commitments, please read Note 9(a) to
our consolidated financial statements.
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 formed a bankruptcy remote subsidiary, which we
consolidate, 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 Sheets. In January 2004, the $100 million receivables
facility was replaced with a $250 million receivables facility terminating in
January 2005. In January 2005, the facility was extended to January 2006 and
temporarily increased, for the period from January 2005 to June 2005, to $375
million. For additional information regarding this transaction please read Note
2(i) to our consolidated financial statements.
Credit Facilities. As of March 11, 2005, we had a $250 million credit
facility under which no borrowings had been made. The credit facility terminates
on March 23, 2007.
Securities Registered with the SEC. At December 31, 2004, we had a shelf
registration statement covering $50 million of debt securities.
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 applicable to registered public utility holding companies
under the 1935 Act and under an order from the SEC dated June 30, 2003 (June
2003 Financing Order) relating to our financing activities. The order expires in
June 2005; however, we will seek approval for subsequent participation in the
money pool prior to that date. Our money pool borrowing limit under such
financing orders is $600 million. At December 31, 2004, we had $42 million
invested in the money pool. The money pool may not provide sufficient funds to
meet our cash needs.
Impact on Liquidity of a Downgrade in Credit Ratings. As of March 24, 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 REVIEW(1) RATING OUTLOOK(2) RATING OUTLOOK(3)
- ------ ---------------- ------ ---------- ------ ----------
Ba1 Possible Upgrade BBB Negative BBB Stable
- ----------
(1) A "review for possible upgrade" from Moody's indicates that a rating is
under review for possible change in the short-term, usually within 90 days.
(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
6
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 would increase borrowing costs under our $250
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
Ability to Issue Securities 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.
Our credit facility contains a "material adverse change" clause which
relates to our ability to perform our obligations under the credit agreement.
CenterPoint Energy Gas Services, Inc. (CEGS), one of our wholly owned
subsidiaries, provides comprehensive natural gas sales and services to
industrial and commercial customers that are primarily located within or near
the territories served by our pipelines and natural gas distribution
subsidiaries. In order to hedge its exposure to natural gas prices, CEGS 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. As of
December 31, 2004, our senior unsecured debt was rated BBB by S&P and Ba1 by
Moody's. We estimate that as of December 31, 2004, unsecured credit limits
extended to CEGS by counterparties could aggregate $100 million; however,
utilized credit capacity is significantly lower.
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 February 28, 2005, CenterPoint Energy had issued five
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:
- 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 for storage;
- increases in interest expense in connection with debt refinancings;
- various regulatory actions; and
- various of the risks identified under "Risk Factors" in Item 1 of the
CERC Corp. Form 10-K.
Certain Contractual and Regulatory Limits on Ability to Issue Securities
and Pay Dividends. Limitations imposed on us under the 1935 Act affect our
ability to issue securities, pay dividends on our common stock or take other
actions to adjust our capitalization.
Our bank facility and our receivables facility limit our debt as a
percentage of our total capitalization to 60% and contain an earnings before
interest, taxes, depreciation and amortization (EBITDA) to interest covenant.
7
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.
The June 2003 Financing Order is effective until June 30, 2005.
Additionally, CenterPoint Energy has received several subsequent orders which
provide additional financing authority. These orders establish 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 permit CenterPoint Energy and its regulated
subsidiaries, including us, to refinance our existing obligations. We are in
compliance with the authorized limits. The orders also permit our utilization of
undrawn credit facilities. As of February 28, 2005, we are authorized to issue
an additional $2 million of debt and an additional aggregate $250 million of
preferred stock and preferred securities. The SEC has reserved jurisdiction
over, and must take further action to permit, the issuance of $430 million of
additional debt by us.
The orders require that if CenterPoint Energy or any of its regulated
subsidiaries, including us, issue any securities that are rated by a nationally
recognized statistical rating organization (NRSRO), the security to be issued
must obtain an investment grade rating from at least one NRSRO and, as a
condition to such issuance, all outstanding rated securities of the issuer and
of CenterPoint Energy must be rated investment grade by at least one NRSRO. The
orders also contain certain requirements for interest rates, maturities,
issuance expenses and use of proceeds.
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 2003 Financing Order requires us to maintain a
ratio of common equity to total capitalization of 30%.
Relationship with CenterPoint Energy. We are an indirect wholly owned
subsidiary of CenterPoint Energy. As a result of this relationship, the
financial condition and liquidity of our parent company could affect our access
to capital, our credit standing and our financial condition.
CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one that is both important to the
presentation of our financial condition and results of operations and requires
management to make difficult, subjective or complex accounting estimates. An
accounting estimate is an approximation made by management of a financial
statement element, item or account in the financial statements. Accounting
estimates in our historical consolidated financial statements measure the
effects of past business transactions or events, or the present status of an
asset or liability. The accounting estimates described below require us to make
assumptions about matters that are highly uncertain at the time the estimate is
made. Additionally, different estimates that we could have used or changes in an
accounting estimate that are reasonably likely to occur could have a material
impact on the presentation of our financial condition or results of operations.
The circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the effect of matters that are
inherently uncertain. Estimates and assumptions about future events and their
effects cannot be predicted with certainty. We base our estimates on historical
experience and on various other assumptions that we believe to be reasonable
under the circumstances, the results of which form the basis for making
judgments. These estimates may change as new events occur, as more experience is
acquired, as additional information is obtained and as our operating environment
changes. Our significant accounting policies are discussed in Note 2 to our
consolidated financial statements. We believe the following accounting policies
involve the application of critical accounting estimates. Accordingly, these
accounting estimates have been reviewed and discussed with the audit committee
of the board of directors of CenterPoint Energy.
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 annually for
8
goodwill as required by SFAS No. 142, "Goodwill and Other Intangible Assets." No
impairment of goodwill was indicated based on our analysis as of January 1,
2004. 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.
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(n) to the consolidated financial statements, incorporated herein
by reference, for a discussion of new accounting pronouncements that affect us.
OTHER SIGNIFICANT MATTERS
Pension Plan. As discussed in Note 7(a) to our consolidated financial
statements, we participate in CenterPoint Energy's qualified non-contributory
pension plan covering substantially all employees. Pension expense for 2005 is
estimated to be $15 million based on an expected return on plan assets of 8.5%
and a discount rate of 5.75% as of December 31, 2004. Pension expense for the
year ended December 31, 2004 was $35 million. Future changes in plan asset
returns, assumed discount rates and various other factors related to the pension
will impact our future pension expense. We cannot predict with certainty what
these factors will be in the future.
9
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED INCOME
YEAR ENDED DECEMBER 31,
----------------------------------------
2004
(AS RESTATED -
2002 2003 SEE NOTE 13)
---------- ---------- --------------
(IN THOUSANDS)
REVENUES ............................... $4,207,836 $5,649,720 $6,472,478
---------- ---------- ----------
EXPENSES:
Natural gas ......................... 2,900,682 4,296,928 5,013,484
Operation and maintenance ........... 666,502 688,639 731,959
Depreciation and amortization ....... 167,456 175,975 187,228
Taxes other than income taxes ....... 119,911 129,846 146,891
---------- ---------- ----------
Total ............................ 3,854,551 5,291,388 6,079,562
---------- ---------- ----------
OPERATING INCOME ....................... 353,285 358,332 392,916
---------- ---------- ----------
OTHER INCOME (EXPENSE):
Interest and other finance charges .. (153,713) (178,985) (178,185)
Other, net .......................... 8,131 8,237 15,875
---------- ---------- ----------
Total ............................ (145,582) (170,748) (162,310)
---------- ---------- ----------
INCOME BEFORE INCOME TAXES ............. 207,703 187,584 230,606
Income Tax Expense .................. (87,643) (58,706) (86,497)
---------- ---------- ----------
NET INCOME ............................. $ 120,060 $ 128,878 $ 144,109
========== ========== ==========
See Notes to the Company's Consolidated Financial Statements
10
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
YEAR ENDED DECEMBER 31,
------------------------------
2002 2003 2004
-------- -------- --------
(IN THOUSANDS)
Net income ................................................. $120,060 $128,878 $144,109
-------- -------- --------
Other comprehensive income (loss), net of tax:
Minimum non-qualified pension liability adjustment
(net of tax of $790) ................................. 1,468 -- --
Net deferred gain (loss) from cash flow hedges
(net of tax of $35,142, $15,405 and $30,740) ......... 46,062 21,971 59,104
Reclassification of net deferred loss (gain) from cash
flow hedges realized in net income (net of tax
of $5,681, $569 and $12,236) ......................... 381 1,297 (23,403)
Reclassification of deferred gain from de-designation
of cash flow hedges to over/under recovery of gas
costs (net of tax of $36,766) ........................ -- -- (68,280)
-------- -------- --------
Other comprehensive income (loss) .......................... 47,911 23,268 (32,579)
-------- -------- --------
Comprehensive income ....................................... $167,971 $152,146 $111,530
======== ======== ========
See Notes to the Company's Consolidated Financial Statements
11
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
---------------------------
2004
(AS RESTATED -
2003 SEE NOTE 13)
---------- --------------
(IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ................................... $ 34,447 $ 140,466
Accounts receivable, net .................................... 462,988 545,348
Accrued unbilled revenue .................................... 323,844 502,163
Accounts and notes receivable -- affiliated companies, net .. -- 11,987
Inventory ................................................... 187,226 200,801
Non-trading derivative assets ............................... 45,897 50,219
Taxes receivable ............................................ 32,023 155,155
Deferred tax asset .......................................... -- 12,256
Prepaid expenses ............................................ 11,104 8,308
Other ....................................................... 71,597 92,160
---------- ----------
Total current assets ..................................... 1,169,126 1,718,863
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, NET ............................. 3,735,561 3,834,083
---------- ----------
OTHER ASSETS:
Goodwill, net ............................................... 1,740,510 1,740,510
Other intangibles, net ...................................... 20,101 19,719
Non-trading derivative assets ............................... 11,273 17,682
Accounts and notes receivable -- affiliated companies, net .. 33,929 18,197
Other ....................................................... 142,162 118,089
---------- ----------
Total other assets ....................................... 1,947,975 1,914,197
---------- ----------
TOTAL ASSETS ............................................. $6,852,662 $7,467,143
========== ==========
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES:
Short-term borrowings ....................................... $ 63,000 $ --
Current portion of long-term debt ........................... -- 366,873
Accounts payable ............................................ 528,394 732,853
Accounts and notes payable -- affiliated companies, net ..... 23,351 --
Taxes accrued ............................................... 65,636 77,802
Interest accrued ............................................ 58,505 57,741
Customer deposits ........................................... 58,372 60,164
Non-trading derivative liabilities .......................... 6,537 26,323
Accumulated deferred income taxes, net ...................... 8,856 --
Other ....................................................... 125,132 272,996
---------- ----------
Total current liabilities ................................ 937,783 1,594,752
---------- ----------
OTHER LIABILITIES:
Accumulated deferred income taxes, net ...................... 645,125 640,780
Non-trading derivative liabilities .......................... 3,330 6,412
Benefit obligations ......................................... 130,980 128,537
Other ....................................................... 571,005 556,819
---------- ----------
Total other liabilities .................................. 1,350,440 1,332,548
---------- ----------
LONG-TERM DEBT ................................................. 2,370,974 2,000,696
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTE 9)
STOCKHOLDER'S EQUITY ........................................... 2,193,465 2,539,147
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY ............... $6,852,662 $7,467,143
========== ==========
See Notes to the Company's Consolidated Financial Statements
12
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEAR ENDED DECEMBER 31,
--------------------------------------
2004
(AS RESTATED -
2002 2003 SEE NOTE 13)
--------- --------- --------------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................ $ 120,060 $ 128,878 $ 144,109
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization .......................... 167,456 175,975 187,228
Deferred income taxes .................................. 23,003 25,097 (8,332)
Amortization of deferred financing costs ............... 2,770 8,424 9,618
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net ...... 3,275 (121,864) (162,759)
Accounts receivable/payable, affiliates ............. (65,688) (3,784) 6,519
Inventory ........................................... 8,762 (51,519) (13,575)
Taxes receivable .................................... (61,512) 29,489 118,387
Accounts payable .................................... 198,045 58,062 207,989
Fuel cost recovery .................................. 28,317 25,420 25,212
Interest and taxes accrued .......................... 7,653 18,000 11,402
Net non-trading derivative assets and liabilities ... 13,527 17,828 (38,964)
Other current assets ................................ (32,833) (36,998) (17,783)
Other current liabilities ........................... 11,604 (1,268) (20,332)
Other assets ........................................ 100,118 19,663 47,224
Other liabilities ................................... (92,064) 40,250 (6,454)
Other, net ............................................. 1,370 (14,481) (3,405)
--------- --------- ---------
Net cash provided by operating activities ........ 433,863 317,172 486,084
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ...................................... (266,208) (265,061) (269,395)
Decrease (increase) in affiliate notes receivable ......... 96,562 5,168 (30,322)
Other, net ................................................ 9,726 (7,581) (3,163)
--------- --------- ---------
Net cash used in investing activities ............ (159,920) (267,474) (302,880)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of long-term debt ................................ (6,653) (507,795) --
Proceeds from long-term debt .............................. -- 928,525 --
Increase (decrease) in short-term borrowings, net ......... 1,473 (284,000) (63,000)
Increase (decrease) in notes with affiliates, net ......... 74,096 (74,096) --
Dividends to parent ....................................... (350,000) -- (12,500)
Debt issuance costs ....................................... -- (87,122) (1,685)
Other, net ................................................ (47) -- --
--------- --------- ---------
Net cash used in financing activities ............ (281,131) (24,488) (77,185)
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ......... (7,188) 25,210 106,019
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE YEAR ........... 16,425 9,237 34,447
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF THE YEAR ................. $ 9,237 $ 34,447 $ 140,466
========= ========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest ............................................... $ 146,244 $ 164,040 $ 175,871
Income taxes (refunds) ................................. 125,085 (49,033) 41,846
See Notes to the Company's Consolidated Financial Statements
13
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED STOCKHOLDER'S EQUITY
2002 2003 2004
------------------- ------------------- -------------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
------ ---------- ------ ---------- ------ ----------
(IN THOUSANDS OF DOLLARS AND SHARES)
COMMON STOCK
Balance, beginning of year ................................. 1,000 $ 1 1,000 $ 1 1,000 $ 1
----- ---------- ----- ---------- ----- ----------
Balance, end of year ....................................... 1,000 1 1,000 1 1,000 1
----- ---------- ----- ---------- ----- ----------
ADDITIONAL PAID-IN-CAPITAL
Balance, beginning of year ................................. 2,255,395 1,986,364 1,985,254
Dividend to parent ......................................... (272,907) -- --
Contributions from parent .................................. 3,876 -- 246,652
Other ...................................................... -- (1,110) --
---------- ---------- ----------
Balance, end of year ....................................... 1,986,364 1,985,254 2,231,906
---------- ---------- ----------
RETAINED EARNINGS
Balance, beginning of year ................................. 1,837 44,804 173,682
Net income ................................................. 120,060 128,878 144,109
Dividend to parent ......................................... (77,093) -- (12,500)
---------- ---------- ----------
Balance, end of year ....................................... 44,804 173,682 305,291
---------- ---------- ----------
ACCUMULATED OTHER COMPREHENSIVE INCOME
Balance, end of year:
Net deferred gain from cash flow hedges .................... 11,260 34,528 1,949
---------- ---------- ----------
Total accumulated other comprehensive income, end of year .. 11,260 34,528 1,949
---------- ---------- ----------
Total Stockholder's Equity ................................. $2,042,429 $2,193,465 $2,539,147
========== ========== ==========
See Notes to the Company's Consolidated Financial Statements
14
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BACKGROUND AND BASIS OF PRESENTATION
CenterPoint Energy Resources Corp. (CERC Corp., and, together with its
subsidiaries, the Company), owns and operates natural gas distribution
facilities, interstate pipelines and natural gas gathering, processing and
treating facilities. CERC Corp. is a Delaware corporation.
The Company's operations of its local distribution companies are conducted
by three unincorporated divisions: Houston Gas, Minnesota Gas and Southern Gas
Operations. In 2004, the naming conventions of the Company's three
unincorporated divisions were changed in an effort to increase brand
recognition. CenterPoint Energy Arkla and the portion of CenterPoint Energy
Entex (Entex) located outside of the metropolitan Houston area were renamed
Southern Gas Operations. The metropolitan Houston portion of Entex was renamed
Houston Gas, and CenterPoint Energy Minnegasco was renamed Minnesota 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). 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 regulated
subsidiaries. The 1935 Act, among other things, limits the ability of
CenterPoint Energy and its regulated 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.
Basis of Presentation
The Company's reportable business segments include the following: Natural
Gas Distribution, Pipelines and Gathering and Other Operations. Natural Gas
Distribution consists of intrastate natural gas sales to, and natural gas
transportation and distribution for, residential, commercial, industrial and
institutional customers and non-rate regulated retail gas marketing operations
for commercial and industrial customers. Pipelines and Gathering includes the
interstate natural gas pipeline operations and the natural gas gathering and
pipeline services businesses. Other Operations consists primarily of other
corporate operations which support all of the Company's business operations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) RECLASSIFICATIONS AND USE OF ESTIMATES
Some amounts from the previous years have been reclassified to conform to
the 2004 presentation of financial statements. These reclassifications do not
affect net income.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities,
disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
(B) PRINCIPLES OF CONSOLIDATION
The accounts of CERC Corp. and its wholly owned and majority owned
subsidiaries are included in the Company's consolidated financial statements.
All significant intercompany transactions and balances are eliminated
15
in consolidation. The Company uses the equity method of accounting for
investments in entities in which the Company has an ownership interest between
20% and 50% and exercises significant influence. Other investments, excluding
marketable securities, are carried at cost.
(C) REVENUES
The Company records revenue for natural gas sales and services under the
accrual method and these revenues are recognized upon delivery to customers.
Natural gas sales not billed by month-end are accrued based upon estimated
purchased gas volumes, estimated lost and unaccounted for gas and currently
effective tariff rates. The Pipelines and Gathering business segment records
revenues as transportation services are provided.
(D) LONG-LIVED ASSETS AND INTANGIBLES
The Company records property, plant and equipment at historical cost. The
Company expenses repair and maintenance costs as incurred. Property, plant and
equipment includes the following:
DECEMBER 31,
ESTIMATED USEFUL ---------------
LIVES (YEARS) 2003 2004
---------------- ------ ------
(IN MILLIONS)
Natural gas distribution ................ 5-50 $2,316 $2,494
Pipelines and gathering ................. 5-75 1,722 1,767
Other property .......................... 3-40 49 35
------ ------
Total ................................ 4,087 4,296
Accumulated depreciation ................ (351) (462)
------ ------
Property, plant and equipment, net ... $3,736 $3,834
====== ======
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2003 DECEMBER 31, 2004
----------------------- -----------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Land Use Rights ..... $ 7 $(3) $ 7 $(3)
Other ............... 20 (4) 21 (5)
--- --- --- ---
Total ............ $27 $(7) $28 $(8)
=== === === ===
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
December 31, 2004 other than goodwill discussed below. 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
rights and 4 to 25 years for other intangibles.
Amortization expense for other intangibles for the years ended December
2002, 2003 and 2004 was $1 million, $2 million and $2 million, respectively.
Estimated amortization expense is approximately $2 million per year for the five
succeeding fiscal years.
Goodwill by reportable business segment is as follows (in millions):
DECEMBER 31,
2003 AND 2004
-------------
Natural Gas Distribution .. $1,085
Pipelines and Gathering ... 601
Other Operations .......... 55
------
Total ................... $1,741
======
16
The Company reviews the carrying value of goodwill annually and at such
times when events or changes in circumstances indicate that it may not be
recoverable. The Company completed its annual evaluation of goodwill for
impairment as of January 1, 2004 and no impairment was indicated.
The Company periodically evaluates long-lived assets, including property,
plant and equipment, and specifically identifiable intangibles, when events or
changes in circumstances indicate that the carrying value of these assets may
not be recoverable. The determination of whether an impairment has occurred is
based on an estimate of undiscounted cash flows attributable to the assets, as
compared to the carrying value of the assets. A resulting impairment loss is
highly dependent on these underlying assumptions.
(E) REGULATORY ASSETS AND LIABILITIES
The Company applies the accounting policies established in SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the
accounts of the utility operations of the Natural Gas Distribution business
segment and to some of the accounts of the Pipelines and Gathering business
segment.
The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheets as of December 31, 2003 and 2004:
DECEMBER 31,
-------------
2003 2004
----- -----
(IN MILLIONS)
Regulatory assets in other long-term assets ............ $ 34 $ 21
Regulatory liabilities in other long-term liabilities .. (434) (433)
----- -----
Total ............................................... $(400) $(412)
===== =====
If events were to occur that would make the recovery of these assets and
liabilities no longer probable, the Company would be required to write-off or
write-down these regulatory assets and liabilities.
The Company's rate-regulated businesses recognize removal costs as a
component of depreciation expense in accordance with regulatory treatment. As of
December 31, 2003 and 2004, these removal costs of $415 million and $428
million, respectively, are classified as regulatory liabilities in the
Consolidated Balance Sheets. The Company has also identified other asset
retirement obligations that cannot be estimated because the assets associated
with the retirement obligations have an indeterminate life.
(F) DEPRECIATION AND AMORTIZATION EXPENSE
Depreciation is computed using the straight-line method based on economic
lives or a regulatory-mandated recovery period. Other amortization expense
includes amortization of regulatory assets and other intangibles.
The following table presents depreciation and other amortization expense
for 2002, 2003 and 2004.
YEAR ENDED DECEMBER 31,
-----------------------
2002 2003 2004
---- ---- ----
(IN MILLIONS)
Depreciation expense ............................ $153 $161 $171
Other amortization expense ...................... 14 15 16
---- ---- ----
Total depreciation and amortization expense .. $167 $176 $187
==== ==== ====
(G) CAPITALIZATION OF INTEREST AND ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction (AFUDC) represents the
approximate net composite interest cost of borrowed funds and a reasonable
return on the equity funds used for construction. Although AFUDC increases both
utility plant and earnings, it is realized in cash through depreciation
provisions included in rates for subsidiaries that apply SFAS No. 71. Interest
and AFUDC for subsidiaries that apply SFAS No. 71 are capitalized as a component
of
17
projects under construction and will be amortized over the assets' estimated
useful lives. During 2002, 2003 and 2004, the Company capitalized interest and
AFUDC of $1 million, $1 million and $2 million, respectively.
(H) INCOME TAXES
The Company is included in the consolidated income tax returns of
CenterPoint Energy. The Company calculates its income tax provision on a
separate return basis under a tax sharing agreement with CenterPoint Energy.
Pursuant to the tax sharing agreement with CenterPoint Energy, in 2004, the
Company received an allocation of CenterPoint Energy's tax benefits totaling
$171 million. The Company uses the liability method of accounting for deferred
income taxes and measures deferred income taxes for all significant income tax
temporary differences. Investment tax credits were deferred and are being
amortized over the estimated lives of the related property. Current federal and
certain state income taxes are payable to or receivable from CenterPoint Energy.
For additional information regarding income taxes, see Note 8.
(I) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS
Accounts receivable are net of an allowance for doubtful accounts of $28
million at December 31, 2003 and 2004. The provision for doubtful accounts in
the Company's Statements of Consolidated Income for 2002, 2003 and 2004 was $15
million, $24 million and $26 million, respectively.
In connection with the Company's November 2002 amendment and extension of
its $150 million receivables facility, CERC Corp. formed a bankruptcy remote
subsidiary for the sole purpose of buying receivables created by the Company and
selling those receivables to an unrelated third-party. This transaction was
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," (SFAS No. 140) and, as a result, the related receivables are
excluded from the Consolidated Balance Sheets. The bankruptcy remote subsidiary
purchases receivables with cash and subordinated notes. In July 2003, the
subordinated notes owned by the Company were pledged to a gas supplier to secure
obligations incurred in connection with the purchase of gas by the Company.
Effective June 25, 2003, the Company reduced the purchase limit under the
receivables facility from $150 million to $100 million. As of December 31, 2003,
the Company had utilized $100 million of its receivables facility.
In the first quarter of 2004, the Company replaced the receivables facility
with a $250 million committed one-year receivables facility. The bankruptcy
remote subsidiary continues to buy the Company's receivables and sell them to an
unrelated third-party, which transactions are accounted for as a sale of
receivables under SFAS No. 140. As of December 31, 2004, the Company had
utilized $181 million of its receivables facility.
The average outstanding balances on the receivables facilities were $16
million, $100 million and $190 million in 2002, 2003 and 2004, respectively.
Sales of receivables were approximately $0.2 billion, $1.2 billion and $2.4
billion in 2002, 2003 and 2004.
(J) INVENTORY
Inventory consists principally of materials and supplies and natural gas.
Inventories used in the retail natural gas distribution operations are primarily
valued at the lower of average cost or market.
DECEMBER 31,
-------------
2003 2004
---- ----
(IN MILLIONS)
Materials and supplies .. $ 27 $ 25
Natural gas ............. 160 176
---- ----
Total inventory ...... $187 $201
==== ====
(K) INVESTMENT IN OTHER DEBT AND EQUITY SECURITIES
In accordance with SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities" (SFAS No. 115), the Company reports
"available-for-sale" securities at estimated fair value within other long-term
assets in
18
the Company's Consolidated Balance Sheets and any unrealized gain or loss, net
of tax, as a separate component of stockholders' equity and accumulated other
comprehensive income. In accordance with SFAS No. 115, the Company reports
"trading" securities at estimated fair value in the Company's Consolidated
Balance Sheets, and any unrealized holding gains and losses are recorded as
other income (expense) in the Company's Statements of Consolidated Income.
As of December 31, 2003 and 2004, the Company held no "available-for-sale"
or "trading" securities.
(L) ENVIRONMENTAL COSTS
The Company expenses or capitalizes environmental expenditures, as
appropriate, depending on their future economic benefit. The Company expenses
amounts that relate to an existing condition caused by past operations, and that
do not have future economic benefit. The Company records undiscounted
liabilities related to these future costs when environmental assessments and/or
remediation activities are probable and the costs can be reasonably estimated.
(M) STATEMENTS OF CONSOLIDATED CASH FLOWS
For purposes of reporting cash flows, the Company considers cash
equivalents to be short-term, highly liquid investments with maturities of three
months or less from the date of purchase.
(N) NEW ACCOUNTING PRONOUNCEMENTS
In January 2003, the Financial Accounting Standards Board (FASB) issued
FASB Interpretation No. (FIN) 46 "Consolidation of Variable Interest Entities,
an Interpretation of Accounting Research Bulletin No. 51" (FIN 46). FIN 46
requires certain variable interest entities to be consolidated by the primary
beneficiary of the entity if the equity investors in the entity do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. On December 24, 2003, the
FASB issued a revision to FIN 46 (FIN 46-R). For special-purpose entities (SPEs)
created before February 1, 2003, the Company applied the provisions of FIN 46 or
FIN 46-R as of December 31, 2003. FIN 46-R is effective for all other entities
for financial periods ending after March 15, 2004. The Company has a subsidiary
trust that has Mandatorily Redeemable Preferred Securities outstanding. The
trust was determined to be a variable interest entity under FIN 46-R and the
Company also determined that it is not the primary beneficiary of the trust. As
of December 31, 2003, the Company deconsolidated the trust and instead reports
its junior subordinated debentures due to the trust as long-term debt.
On May 19, 2004, the FASB issued a FASB Staff Position (FSP) addressing the
appropriate accounting and disclosure requirements for companies that sponsor a
postretirement health care plan that provides prescription drug benefits. The
new guidance from the FASB was deemed necessary as a result of the 2003 Medicare
prescription law, which includes a federal subsidy for qualifying companies. FSP
106-2, "Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003" (FSP 106-2),
requires that the effects of the federal subsidy be considered an actuarial gain
and treated like similar gains and losses and requires certain disclosures for
employers that sponsor postretirement health care plans that provide
prescription drug benefits. The FASB's related existing guidance, FSP 106-1,
"Accounting and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003," was superseded upon the
effective date of FSP 106-2. The Company adopted FSP 106-2 prospectively in July
2004 with no material effect on its results of operations, financial condition
or cash flows.
3. REGULATORY MATTERS
(A) RATE CASES
In 2004, the City of Houston, 28 other cities and the Railroad Commission
of Texas (Railroad Commission) approved a settlement that increased Houston Gas'
base rate and service charge revenues by approximately $14 million annually.
19
In February 2004, the Louisiana Public Service Commission (LPSC) approved a
settlement that increased Southern Gas Operations' base rate and service charge
revenues in its South Louisiana Division by approximately $2 million annually.
In July 2004, Minnesota Gas filed an application for a general rate
increase of $22 million with the Minnesota Public Utilities Commission (MPUC).
Minnesota Gas and the Minnesota Department of Commerce have agreed to a
settlement of all issues, including an annualized increase in the amount of $9
million, subject to approval by the MPUC. A final decision on this rate relief
request is expected from the MPUC in the second quarter of 2005. Interim rates
of $17 million on an annualized basis became effective on October 1, 2004,
subject to refund.
In July 2004, the LPSC approved a settlement that increased Southern Gas
Operations' base rate and service charge revenues in its North Louisiana
Division by approximately $7 million annually.
In October 2004, Southern Gas Operations filed an application for a general
rate increase of approximately $3 million with the Railroad Commission for rate
relief in the unincorporated areas of its Beaumont, East Texas and South Texas
Divisions. The Railroad Commission staff has begun its review of the request,
and a decision is anticipated in April 2005.
In November 2004, Southern Gas Operations filed an application for a
general rate increase of approximately $34 million with the Arkansas Public
Service Commission (APSC). The APSC staff has begun its review of the request,
and a decision is anticipated in the second half of 2005.
In December 2004, the Oklahoma Corporation Commission approved a settlement
that increased Southern Gas Operations' base rate and service charge revenues in
Oklahoma by approximately $3 million annually.
(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
has been 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 ending October 31, 2002. In December
2004, the Railroad Commission conducted a hearing on the matter and is expected
to issue a ruling in March or April of 2005. In a parallel action now in the
Court of Appeals in Austin, Southern Gas Operations is challenging the scope of
the Railroad Commission's inquiry which goes beyond the issue of whether
Southern Gas Operations had properly followed its tariffs to include a review of
Southern Gas Operations' historical gas purchases. The Company believes such a
review is not permitted by law and is beyond what the parties requested in the
joint petition that initiated the proceeding at the Railroad Commission. The
Company believes that all costs for Southern Gas Operations' Tyler distribution
system have been properly included and recovered from customers pursuant to
Southern Gas Operations' filed tariffs.
20
4. RELATED PARTY TRANSACTIONS
The following table summarizes receivables from, or payables to,
CenterPoint Energy or its subsidiaries:
DECEMBER 31,
-------------
2003 2004
---- ----
(IN MILLIONS)
Accounts receivable from affiliates ...................................... $ 6 $ 4
Accounts payable to affiliates ........................................... (29) (34)
Note receivable from affiliates(1) ....................................... -- 42
---- ----
Accounts and notes receivable/(payable) -- affiliated companies, net .. $(23) $ 12
==== ====
Long-term accounts receivable from affiliates ............................ $ -- $ 64
Long-term accounts payable to affiliates ................................. -- (45)
Long-term notes receivable from affiliates ............................... 67 --
Long-term notes payable to affiliates .................................... (33) (1)
---- ----
Long-term accounts and notes receivable -- affiliated companies, net .. $ 34 $ 18
==== ====
- ----------
(1) This note represents money pool investments.
For the years ended December 31, 2002, 2003 and 2004, the Company had net
interest income (expense) related to affiliate borrowings of $(2) million, $3
million and $9 million, respectively.
The 1935 Act generally prohibits borrowings by CenterPoint Energy from its
subsidiaries, including the Company, either through the money pool or otherwise.
During 2002, the sales and services by the Company to Reliant Resources,
Inc., (now named Reliant Energy, Inc.) (RRI), a former affiliate, totaled $42
million. During 2002, 2003 and 2004, the sales and services by the Company to
Texas Genco Holdings, Inc. (Texas Genco), a power generation affiliate, totaled
$28 million, $31 million and $22 million, respectively.
CenterPoint Energy provides some corporate services to the Company. The
costs of services have been charged directly to the Company using methods that
management believes are reasonable. These methods include negotiated usage
rates, dedicated asset assignment, and proportionate corporate formulas based on
assets, 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 $107 million,
$113 million and $116 million for 2002, 2003 and 2004, respectively, and are
included primarily in operation and maintenance expenses.
In 2004, the Company paid a dividend of $12.5 million to Utility Holding,
LLC.
5. DERIVATIVE INSTRUMENTS
The Company is exposed to various market risks. These risks arise from
transactions entered into in the normal course of business. The Company utilizes
derivative financial instruments such as physical forward contracts, swaps and
options (Energy Derivatives) to mitigate the impact of changes in its natural
gas businesses on its operating results and cash flows.
(A) NON-TRADING ACTIVITIES
Cash Flow Hedges. To reduce the risk from market fluctuations associated
with purchased gas costs, the Company enters into energy derivatives in order to
hedge certain expected purchases and sales of natural gas (non-trading energy
derivatives). The Company applies hedge accounting for its non-trading energy
derivatives utilized in non-trading activities only if there is a high
correlation between price movements in the derivative and the item designated as
being hedged. The Company analyzes its physical transaction portfolio to
determine its net exposure by delivery location and delivery period. Because the
Company's physical transactions with similar delivery locations and periods are
highly correlated and share similar risk exposures, the Company facilitates
hedging for
21
customers by aggregating physical transactions and subsequently entering into
non-trading energy derivatives to mitigate exposures created by the physical
positions.
During 2004, hedge ineffectiveness of $0.4 million was recognized in
earnings from derivatives that are designated and qualify as Cash Flow Hedges,
and in 2003 and 2002, no hedge ineffectiveness was recognized. 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 Income 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 December 31, 2004, the Company expects $5
million in accumulated other comprehensive income to be reclassified into net
income during the next twelve months.
The maximum length of time the Company is hedging its exposure to the
variability in future cash flows for forecasted transactions on existing
financial instruments is primarily two years with a limited amount of exposure
up to five years. The Company's policy is not to exceed five years in hedging
its exposure.
Other Derivative Financial Instruments. The Company also has natural gas
contracts which are derivatives which are not hedged. Load following services
that the Company offers its natural gas customers create an inherent tendency 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 aggregate Value at Risk (VaR) associated with these operations is calculated
daily and averaged $0.2 million with a high of $1 million during 2004. 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 2004, the Company recognized net gains related to unhedged positions
amounting to $7 million and as of December 31, 2004 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.
(B) CREDIT RISKS
In addition to the risk associated with price movements, credit risk is
also inherent in the Company's non-trading derivative activities. Credit risk
relates to the risk of loss resulting from non-performance of contractual
obligations by a counterparty. The following table shows the composition of the
non-trading derivative assets of the Company as of December 31, 2003 and 2004
(in millions):
DECEMBER 31, 2003 DECEMBER 31, 2004
------------------- ----------------------
INVESTMENT INVESTMENT
GRADE(1)(2) TOTAL GRADE(1)(2) TOTAL(3)
----------- ----- ----------- --------
Energy marketers ........ $24 $35 $10 $17
Financial institutions .. 21 21 50 50
Other ................... -- 1 1 1
--- --- --- ---
Total ................ $45 $57 $61 $68
=== === === ===
- ----------
(1) "Investment grade" is primarily determined using publicly available credit
ratings along with the consideration of credit support (such as parent
company guarantees) and collateral, which encompass cash and standby
letters of credit.
(2) For unrated counterparties, the Company performs financial statement
analysis, considering contractual rights and restrictions and collateral,
to create a synthetic credit rating.
(3) The $17 million non-trading derivative asset includes a $6 million asset
due to trades with Reliant Energy Services, Inc. (Reliant Energy Services),
a former affiliate. As of December 31, 2004, Reliant Energy Services did
not have an investment grade rating.
22
(C) GENERAL POLICY
CenterPoint Energy has established a Risk Oversight Committee composed of
corporate and business segment officers that oversees all commodity price and
credit risk activities, including the Company's trading, marketing, risk
management services and hedging activities. The committee's duties are to
establish the Company's commodity risk policies, allocate risk capital within
limits established by CenterPoint Energy's board of directors, approve trading
of new products and commodities, monitor risk positions and ensure compliance
with the Company's risk management policies and procedures and trading limits
established by the CenterPoint Energy's board of directors.
The Company's policies prohibit the use of leveraged financial instruments.
A leveraged financial instrument, for this purpose, is a transaction involving a
derivative whose financial impact will be based on an amount other than the
notional amount or volume of the instrument.
6. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
DECEMBER 31, 2003 DECEMBER 31, 2004
---------------------- ----------------------
LONG-TERM CURRENT(1) LONG-TERM CURRENT(1)
--------- ---------- --------- ----------
(IN MILLIONS)
Short-term borrowings:
Revolving credit facility ........................... $63 $ --
--- ----
Long-term debt:
Convertible subordinated debentures 6.00% due 2012 .. 74 -- 69 6
Senior notes 5.95% to 8.90% due 2005 to 2014 ........ 2,251 -- 1,923 325
Junior subordinated debentures payable to affiliate
6.25% due 2026(2) ................................ 6 -- 6 --
Other .................................................. 36 -- -- 36
Unamortized discount and premium(3) .................... 4 -- 3 --
------ --- ------ ----
Total long-term debt .......................... 2,371 -- 2,001 367
------ --- ------ ----
Total borrowings .............................. $2,371 $63 $2,001 $367
====== === ====== ====
- ----------
(1) Includes amounts due within one year of the date noted.
(2) The junior subordinated debentures were issued to a subsidiary trust in
connection with the issuance by that trust of preferred securities. The
trust preferred securities were deconsolidated effective December 31, 2003
pursuant to the adoption of FIN 46. This resulted in the junior
subordinated debentures held by the trust being reported as long-term debt.
For further discussion, see Note 2(n).
(3) Debt acquired in business acquisitions is adjusted to fair market value as
of the acquisition date. Included in long-term debt is additional
unamortized premium related to fair value adjustments of long-term debt of
$6 million and $5 million at December 31, 2003 and 2004, respectively,
which is being amortized over the remaining term of the related long-term
debt.
(A) SHORT-TERM BORROWINGS
Credit Facilities. As of December 31, 2003, the Company had a revolving
credit facility that provided for an aggregate of $200 million in committed
credit. As of December 31, 2003, $63 million was borrowed under the revolving
credit facility. This facility terminated in March 2004. The weighted average
interest rate on short-term borrowings at December 31, 2003 was 5.0%, excluding
facility fees and other fees paid in connection with the arrangement of the bank
facilities.
(B) LONG-TERM DEBT
As of December 31, 2004, the Company had a revolving credit facility that
provided for an aggregate of $250 million in committed credit. The revolving
credit facility terminates on March 23, 2007. Fully-drawn rates for borrowings
under this facility, including the facility fee, are London inter-bank offered
rate (LIBOR) plus 150 basis
23
points based on current credit ratings and the applicable pricing grid. As of
December 31, 2004, 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. The convertible junior
subordinated debentures represent CERC Trust's sole asset and its entire
operations. 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. As discussed in Note 2(n), upon the
Company's adoption of FIN 46, the junior subordinated debentures discussed above
were included in long-term debt as of December 31, 2003 and 2004.
The convertible preferred securities are mandatorily redeemable upon the
repayment of the convertible junior subordinated debentures at their stated
maturity or earlier redemption. Effective January 7, 2003, the convertible
preferred securities are convertible at the option of the holder into $33.62 of
cash and 2.34 shares of CenterPoint Energy common stock for each $50 of
liquidation value. As of December 31, 2003 and 2004, the liquidation amount of
convertible preferred securities outstanding was $0.4 million and $0.3 million,
respectively. The securities, and their underlying convertible junior
subordinated debentures, bear interest at 6.25% and mature in June 2026. Subject
to some limitations, CERC Corp. has the option of deferring payments of interest
on the convertible junior subordinated debentures. During any deferral or event
of default, CERC Corp. may not pay dividends on its common stock to CenterPoint
Energy. As of December 31, 2004, no interest payments on the convertible junior
subordinated debentures had been deferred.
Maturities. The Company's consolidated maturities of long-term debt and
sinking fund requirements are $367 million in 2005, $158 million in 2006, $7
million in 2007, $307 million in 2008 and $7 million in 2009. The 2005 amount is
net of the portion of a sinking fund payment that can be satisfied with debt
that had been acquired and retired as of December 31, 2004.
(C) RECEIVABLES FACILITY
On January 21, 2004, the Company replaced its $100 million receivables
facility with a $250 million receivables facility. As of December 31, 2004, the
Company had $181 million outstanding under its receivables facility. In January
2005, the 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, in view of
recent levels of, and volatility in, gas prices.
7. EMPLOYEE BENEFIT PLANS
(A) PENSION PLANS
Substantially all of the Company's employees participate in CenterPoint
Energy's qualified non-contributory pension plan. Under the cash balance
formula, participants accumulate a retirement benefit based upon 4% of eligible
earnings and accrued interest. Prior to 1999, the pension plan accrued benefits
based on years of service, final average pay and covered compensation. As a
result, certain employees participating in the plan as of December 31, 1998 are
eligible to receive the greater of the accrued benefit calculated under the
prior plan through 2008 or the cash balance formula.
CenterPoint Energy's funding policy is to review amounts annually in
accordance with applicable regulations in order to achieve adequate funding of
projected benefit obligations. Pension expense is allocated to the Company based
on covered employees. This calculation is intended to allocate pension costs in
the same manner as a separate employer plan. Assets of the plan are not
segregated or restricted by CenterPoint Energy's participating subsidiaries. The
Company recognized pension expense of $13 million, $36 million and $35 million
for the years ended December 31, 2002, 2003 and 2004, respectively.
24
In addition to the Plan, the Company participates in CenterPoint Energy's
non-qualified benefit restoration plan, which allows participants to retain the
benefits to which they would have been entitled under the qualified pension plan
except for federally mandated limits on these benefits or on the level of salary
on which these benefits may be calculated. The expense associated with the
non-qualified pension plan was $2 million, $3 million and less than $1 million
for the years ended December 31, 2002, 2003 and 2004, respectively.
(B) SAVINGS PLAN
The Company participates in CenterPoint Energy's qualified savings plan,
which includes a cash or deferred arrangement under Section 401(k) of the
Internal Revenue Code of 1986, as amended. Under the plan, participating
employees may contribute a portion of their compensation, on a pre-tax or
after-tax basis, generally up to a maximum of 16% of compensation. CenterPoint
Energy matches 75% of the first 6% of each employee's compensation contributed.
CenterPoint Energy may contribute an additional discretionary match of up to 50%
of the first 6% of each employee's compensation contributed. These matching
contributions are fully vested at all times. CenterPoint Energy allocates to the
Company the savings plan benefit expense related to the Company's employees.
Savings plan benefit expense was $17 million, $15 million and $16 million
for the years ended December 31, 2002, 2003 and 2004, respectively.
(C) POSTRETIREMENT BENEFITS
The Company's employees participate in CenterPoint Energy's plans which
provide certain healthcare and life insurance benefits for retired employees on
a contributory and non-contributory basis. Employees become eligible for these
benefits if they have met certain age and service requirements at retirement, as
defined in the plans. Under plan amendments effective in early 1999, healthcare
benefits for future retirees were changed to limit employer contributions for
medical coverage. Such benefit costs are accrued over the active service period
of employees.
The Company is required to fund a portion of its obligations in accordance
with rate orders. All other obligations are funded on a pay-as-you-go basis.
The net postretirement benefit cost includes the following components:
YEAR ENDED DECEMBER 31,
-----------------------
2002 2003 2004
---- ---- ----
(IN MILLIONS)
Service cost -- benefits earned during the period .. $ 2 $ 2 $ 2
Interest cost on projected benefit obligation ...... 9 10 10
Expected return on plan assets ..................... (2) (2) (2)
Net amortization ................................... 2 2 2
Other .............................................. -- -- 1
--- --- ---
Net postretirement benefit cost .................... $11 $12 $13
=== === ===
The Company used the following assumptions to determine net postretirement
benefit costs:
YEAR ENDED
DECEMBER 31,
------------------
2002 2003 2004
---- ---- ----
Discount rate ................... 7.25% 6.75% 6.25%
Expected return on plan assets .. 9.5% 9.0% 8.5%
In determining net periodic benefits cost, the Company uses fair value, as
of the beginning of the year, as its basis for determining expected return on
plan assets.
25
Following are reconciliations of the Company's beginning and ending
balances of its postretirement benefit plans benefit obligation, plan assets and
funded status for 2003 and 2004.
YEAR ENDED DECEMBER 31,
-------------------------------------
2003 2004
----------------- -----------------
(IN MILLIONS)
CHANGE IN BENEFIT OBLIGATION
Accumulated benefit obligation, beginning of year ....... $ 155 $ 171
Service cost ............................................ 2 2
Interest cost ........................................... 10 10
Benefit enhancement ..................................... -- 1
Benefits paid ........................................... (18) (21)
Participant contributions ............................... 4 4
Plan amendments ......................................... (2) --
Actuarial loss .......................................... 20 7
----- -----
Accumulated benefit obligation, end of year ............. $ 171 $ 174
===== =====
CHANGE IN PLAN ASSETS
Plan assets, beginning of year .......................... $ 18 $ 21
Benefits paid ........................................... (18) (21)
Employer contributions .................................. 14 14
Participant contributions ............................... 4 4
Actual investment return ................................ 3 3
----- -----
Plan assets, end of year ................................ $ 21 $ 21
===== =====
RECONCILIATION OF FUNDED STATUS
Funded status ........................................... $(150) $(153)
Unrecognized prior service cost ......................... 15 13
Unrecognized actuarial loss ............................. 40 46
----- -----
Net amount recognized ................................... $ (95) $ (94)
===== =====
AMOUNTS RECOGNIZED IN BALANCE SHEETS
Benefit obligations ..................................... $ (95) $ (94)
----- -----
Net amount recognized at end of year .................... $ (95) $ (94)
===== =====
ACTUARIAL ASSUMPTIONS
Discount rate ........................................... 6.25% 5.75%
Expected long-term return on assets ..................... 8.5% 8.0%
Healthcare cost trend rate assumed for the next year .... 10.50% 9.75%
Rate to which the cost trend rate is assumed to decline
(ultimate trend rate) ................................ 5.5% 5.5%
Year that the rate reaches the ultimate trend rate ...... 2011 2011
Measurement date used to determine plan obligations and
assets................................................ December 31, 2003 December 31, 2004
Assumed healthcare cost trend rates have a significant effect on the
reported amounts for the Company's postretirement benefit plans. A 1% change in
the assumed healthcare cost trend rate would have the following effects:
1% 1%
INCREASE DECREASE
-------- --------
(IN MILLIONS)
Effect on total of service and interest cost ..... $-- $--
Effect on the postretirement benefit obligation .. 6 5
26
The following table displays the weighted average asset allocations as of
December 31, 2003 and 2004 for the Company's postretirement benefit plan:
DECEMBER 31,
------------
2003 2004
---- ----
Domestic equity securities ....... 40% 38%
International equity securities .. 10 11
Debt securities .................. 49 50
Cash ............................. 1 1
--- ---
Total ......................... 100% 100%
=== ===
In managing the investments associated with the postretirement benefit
plan, the Company's objective is to preserve and enhance the value of plan
assets while maintaining an acceptable level of volatility. These objectives are
expected to be achieved through an investment strategy, which manages liquidity
requirements while maintaining a long-term horizon in making investment
decisions and efficient and effective management of plan assets.
As part of the investment strategy discussed above, the Company has adopted
and maintains the following asset allocation ranges for its postretirement
benefit plan:
Domestic equity securities ....... 33-43%
International equity securities .. 5-15%
Debt securities .................. 48-58%
Cash ............................. 0-2%
The expected rate of return assumption was developed by reviewing the
targeted asset allocations and historical index performance of the applicable
asset classes over a 15-year period, adjusted for investment fees and
diversification effects.
The Company expects to contribute $16 million to its postretirement
benefits plan in 2005.
The following benefit payments are expected to be paid by the pension and
postretirement benefit plans:
POSTRETIREMENT
BENEFITS
--------------
(IN MILLIONS)
2005 ....... $ 17
2006 ....... 18
2007 ....... 19
2008 ....... 20
2009 ....... 21
2010-2014 .. 108
(D) POSTEMPLOYMENT BENEFITS
The Company participates in CenterPoint Energy's plan which provides
postemployment benefits for former or inactive employees, their beneficiaries
and covered dependents, after employment but before retirement (primarily
healthcare and life insurance benefits for participants in the long-term
disability plan). Postemployment benefits costs were $6 million, $5 million and
$3 million in 2002, 2003 and 2004, respectively.
(E) OTHER NON-QUALIFIED PLANS
The Company participates in CenterPoint Energy's deferred compensation
plans that provide benefits payable to directors, officers and certain key
employees or their designated beneficiaries at specified future dates, upon
termination, retirement or death. Benefit payments are made from the general
assets of the Company. During 2002, 2003 and 2004, the Company recorded benefits
expense relating to these programs of $1 million each year. Included in "Benefit
Obligations" in the accompanying Consolidated Balance Sheets at December 31,
2003 and 2004, was $10 million and $9 million, respectively, relating to
deferred compensation plans.
27
(F) OTHER EMPLOYEE MATTERS
As of December 31, 2004, approximately 30% of the Company's employees are
subject to collective bargaining agreements. Four of these agreements, covering
approximately 15% of the Company's employees, have expired or will expire in
2005.
8. INCOME TAXES
The Company's current and deferred components of income tax expense are as
follows:
YEAR ENDED DECEMBER 31,
-----------------------
2002 2003 2004
---- ---- ----
(IN MILLIONS)
Current
Federal ............ $56 $30 $86
State .............. 9 4 10
--- --- ---
Total current ... 65 34 96
--- --- ---
Deferred
Federal ............ 12 11 (3)
State .............. 11 14 (6)
--- --- ---
Total deferred .. 23 25 (9)
--- --- ---
Income tax expense .... $88 $59 $87
=== === ===
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
YEAR ENDED DECEMBER 31,
-----------------------
2002 2003 2004
----- ----- -----
(IN MILLIONS)
Income before income taxes ....................... $ 208 $ 188 $ 231
Federal statutory rate ........................ 35% 35% 35%
----- ----- -----
Income tax expense at statutory rate ............. 73 66 81
----- ----- -----
Increase (decrease) in tax resulting from:
Capital loss benefit .......................... (72) -- --
State income taxes, net of valuation allowances
and federal income tax benefit ............. 13 12 2
Valuation allowance, capital loss ............. 72 -- --
Changes in estimates for prior year items ..... -- (19) --
Deferred tax asset write-off .................. -- -- 4
Other, net .................................... 2 -- --
----- ----- -----
Total ...................................... 15 (7) 6
----- ----- -----
Income tax expense ............................... $ 88 $ 59 $ 87
===== ===== =====
Effective Rate ................................... 42.2% 31.3% 37.5%
28
Following are the Company's tax effects of temporary differences between
the carrying amounts of assets and liabilities in the financial statements and
their respective tax bases:
DECEMBER 31,
-------------
2003 2004
---- ----
(IN MILLIONS)
Deferred tax assets:
Current:
Allowance for doubtful accounts ................ 9 13
---- ----
Total current deferred tax assets ........... 9 13
---- ----
Non-current:
Employee benefits .............................. 63 81
Operating and capital loss carryforwards ....... 81 30
Deferred gas costs ............................. 18 68
Other .......................................... 52 66
Valuation allowance ............................ (73) (20)
---- ----
Total non-current deferred tax assets ....... 141 225
---- ----
Total deferred tax assets ................... 150 238
---- ----
Deferred tax liabilities:
Current:
Non-trading derivative liabilities, net ........ 18 1
---- ----
Total current deferred tax liabilities ...... 18 1
---- ----
Non-current:
Depreciation ................................... 746 827
Regulatory liability ........................... 27 17
Other .......................................... 13 22
---- ----
Total non-current deferred tax liabilities .. 786 866
---- ----
Total deferred tax liabilities .............. 804 867
---- ----
Accumulated deferred income taxes, net ...... $654 $629
==== ====
The Company is included in the consolidated income tax returns of
CenterPoint Energy. CenterPoint Energy's consolidated federal income tax returns
have been audited and settled through the 1996 tax year. The 1997 through 2003
consolidated federal income tax returns are currently under audit.
Tax Attribute Carryforwards. At December 31, 2004, the Company had $327
million of state net operating loss carryforwards. The losses are available to
offset future state taxable income through the year 2023. Substantially all of
the state loss carryforwards will expire between 2012 and 2020. A valuation
allowance has been established against approximately 33% of the state net
operating loss carryforwards.
The valuation allowance reflects a net decrease of $10 million and $53
million in 2003 and 2004, respectively. These net changes resulted from a
reassessment of the Company's future ability to use federal and state capital
loss carryforwards and state tax net operating loss carryforwards.
Tax Contingencies. As of December 31, 2004, approximately $13 million of
federal tax reserve has been reclassified to current tax liability. The Company
has also reserved for tax items primarily relating to certain positions taken
with respect to state tax filings. The total amount reserved is approximately
$10 million.
9. COMMITMENTS AND CONTINGENCIES
(A) COMMITMENTS
Environmental Capital Commitments. The Company has various commitments for
capital and environmental expenditures. The Company anticipates no significant
capital and other special project expenditures between 2005 and 2009 for
environmental compliance.
Fuel Commitments. Fuel commitments include several long-term natural gas
contracts related to the Company's natural gas distribution operations, which
have various quantity requirements and durations that are not classified as
non-trading derivative assets and liabilities in the Company's Consolidated
Balance Sheets as of December 31, 2004
29
as these contracts meet the SFAS No. 133 exception to be classified as "normal
purchases contracts" or do not meet the definition of a derivative. Minimum
payment obligations for natural gas supply contracts are approximately $807
million in 2005, $401 million in 2006, $193 million in 2007, $29 million in 2008
and $1 million in 2009.
(B) LEASE COMMITMENTS
The following table sets forth information concerning the Company's
obligations under non-cancelable long-term operating leases, principally
consisting of rental agreements for building space, data processing equipment
and vehicles, including major work equipment (in millions):
2005.............. $20
2006.............. 16
2007.............. 12
2008.............. 11
2009.............. 6
2010 and beyond... 26
---
Total.......... $91
===
Total rental expense for all operating leases was $31 million, $28 million
and $30 million in 2002, 2003 and 2004, respectively.
(C) 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 that the ultimate outcome will have a material impact on its financial
condition or results of operations.
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 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. The plaintiffs allege that defendants inflated the
prices charged to certain consumers of
30
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 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 in the Wharton County case 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. 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 Company and CenterPoint Energy do not anticipate that the
outcome of these matters will have a material impact on the financial condition
or results of operations of either the Company or CenterPoint Energy.
(D) 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 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 believes the ultimate cost associated with resolving this
matter will not have a material impact on the financial condition or results of
operations 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 December 31, 2004, the Company had accrued $18 million for remediation
of certain Minnesota sites. At December 31, 2004, 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
31
remediation methods used. The Company has utilized an environmental expense
tracker mechanism in its rates in Minnesota to recover estimated costs in excess
of insurance recovery. As of December 31, 2004, the Company has collected or
accrued $13 million from insurance companies and ratepayers 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 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. 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 believes that the costs of any remediation of these
sites will not be material to the Company's financial condition, results of
operations or cash flows.
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
believe, based on its experience to date, that these matters, either
individually or in the aggregate, will have a material adverse effect on the
Company's financial condition, results of operations or cash flows.
OTHER PROCEEDINGS
In 2005, the Company received a communication from a regulatory agency
indicating that the agency had ordered a predecessor company to remove certain
components from a portion of its distribution system prior to the date the
Company acquired it. Those components are not in compliance with current state
and federal codes, and it is possible that some of those components remain in
the Company's system. The Company has not completed its analysis of the cost to
locate and replace such components; however, the Company believes that the
disposition of this matter will not have a material adverse effect on the
Company's financial condition, results of operations or cash flows.
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 believes that the disposition of these matters will not have a
material adverse effect on the Company's financial condition, results of
operations or cash flows.
32
10. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair values of cash and cash equivalents, investments in debt and
equity securities classified as "available-for-sale" and "trading" in accordance
with SFAS No. 115, and short-term borrowings are estimated to be approximately
equivalent to carrying amounts and have been excluded from the table below. The
fair values of non-trading derivative assets and liabilities are equivalent to
their carrying amounts in the Consolidated Balance Sheets at December 31, 2003
and 2004 and have been determined using quoted market prices for the same or
similar instruments when available or other estimation techniques (see Note 5).
Therefore, these financial instruments are stated at fair value and are excluded
from the table below.
DECEMBER 31, 2003 DECEMBER 31, 2004
----------------- -----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ------ -------- ------
(IN MILLIONS)
Financial liabilities:
Long-term debt (excluding capital leases) .. $2,371 $2,612 $2,368 $2,659
11. UNAUDITED QUARTERLY INFORMATION
As discussed in Note 13, the unaudited quarterly financial data for the
interim periods ended March 31, 2004, June 30, 2004, September 30, 2004 and
December 31, 2004 have been restated from amounts previously reported.
Summarized quarterly financial data for the years ended December 31, 2003
and 2004 is as follows:
YEAR ENDED DECEMBER 31, 2003
---------------------------------------------------------------
FIRST QUARTER SECOND QUARTER THIRD QUARTER FOURTH QUARTER
------------- -------------- ------------- --------------
(IN MILLIONS)
Revenues ............ $2,094 $1,032 $950 $1,574
Operating income .... 172 67 33 87
Net income (loss) ... 88 15 (10) 36
YEAR ENDED DECEMBER 31, 2004
---------------------------------------------------------------
FIRST QUARTER SECOND QUARTER THIRD QUARTER FOURTH QUARTER
------------- -------------- ------------- --------------
(IN MILLIONS)
Revenues ............ $2,070 $1,217 $1,117 $2,068
Operating income .... 160 64 32 137
Net income (loss) ... 74 11 (2) 61
12. REPORTABLE BUSINESS SEGMENTS
Because the Company is an indirect wholly owned subsidiary of CenterPoint
Energy, the Company's determination of reportable business segments considers
the strategic operating units under which CenterPoint Energy manages sales,
allocates resources and assesses performance of various products and services to
wholesale or retail customers in differing regulatory environments. The
accounting policies of the business segments are the same as those described in
the summary of significant accounting policies except that some executive
benefit costs have not been allocated to business segments.
The Company's reportable business segments include the following: Natural
Gas Distribution, Pipelines and Gathering and Other Operations. Natural Gas
Distribution consists of intrastate natural gas sales to, and natural gas
transportation and distribution for, residential, commercial, industrial and
institutional customers and non-rate regulated retail gas marketing operations
for commercial and industrial customers. Pipelines and Gathering includes the
interstate natural gas pipeline operations and the natural gas gathering and
pipeline services businesses. Other Operations consists primarily of other
corporate operations which support all of the Company's business operations.
Long-lived assets include net property, plant and equipment, net goodwill
and other intangibles and equity investments in unconsolidated subsidiaries. The
Company accounts for intersegment sales as if the sales were to third parties,
that is, at current market prices.
33
Financial data for business segments and products and services are as
follows:
NATURAL GAS PIPELINES AND OTHER RECONCILING
DISTRIBUTION GATHERING OPERATIONS ELIMINATIONS CONSOLIDATED
------------ ------------- ---------- ------------ ------------
(IN MILLIONS)
AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2002:
Revenues from external customers and affiliates ... 3,953 (1) 255 (2) -- -- 4,208
Intersegment revenues ............................. 7 119 -- (126) --
Depreciation and amortization ..................... 126 41 -- -- 167
Operating income .................................. 198 153 2 -- 353
Total assets ...................................... 4,428 2,500 206 (685) 6,449
Expenditures for long-lived assets ................ 196 70 -- -- 266
AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2003:
Revenues from external customers and affiliates ... 5,406 (1) 244 (2) -- -- 5,650
Intersegment revenues ............................. 29 163 9 (201) --
Depreciation and amortization ..................... 136 40 -- -- 176
Operating income (loss) ........................... 202 158 (1) -- 359
Total assets ...................................... 4,661 2,519 388 (715) 6,853
Expenditures for long-lived assets ................ 199 66 -- -- 265
AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2004:
Revenues from external customers and affiliates ... 6,170 (1) 306 (2) (4) -- 6,472
Intersegment revenues ............................. 3 145 5 (153) --
Depreciation and amortization ..................... 143 44 -- -- 187
Operating income (loss) ........................... 222 180 (9) -- 393
Total assets ...................................... 4,732 2,637 792 (694) 7,467
Expenditures for long-lived assets ................ 197 73 (1) -- 269
- ----------
(1) Included in the Natural Gas Distribution revenues from external customers
and affiliates are sales to RRI, a former affiliate, of $9 million for the
year ended December 31, 2002, and sales to Texas Genco, of $26 million, $28
million and $20 million for the years ended December 31, 2002, 2003 and
2004, respectively.
(2) Included in the Pipelines and Gathering revenues from external customers
and affiliates are sales to RRI, a former affiliate, of $33 million for the
year ended December 31, 2002, and sales to Texas Genco of $2 million, $3
million and $2 million for the years ended December 31, 2002, 2003 and
2004, respectively.
YEAR ENDED DECEMBER 31,
------------------------
2002 2003 2004
------ ------ ------
(IN MILLIONS)
REVENUES BY PRODUCTS AND SERVICES:
Retail gas sales .................... $3,857 $5,310 $6,072
Gas transportation .................. 255 244 306
Energy products and services ........ 96 96 94
------ ------ ------
Total ............................ $4,208 $5,650 $6,472
====== ====== ======
13. RESTATEMENT
Subsequent to the issuance of the Company's consolidated financial
statements for the year ended December 31, 2004, CERC Corp. determined that,
during 2004, certain transactions involving purchases and sales of natural gas
among divisions within its Natural Gas Distribution segment were not properly
eliminated in the consolidated financial statements. Consequently, revenues and
natural gas expenses during 2004 were each overstated by approximately $511
million. As a result, the accompanying 2004 consolidated financial statements
have been restated from the amounts previously reported to reflect the
elimination of interdivision purchases and sales of natural gas. There was no
effect on the Company's previously reported operating income, net income or net
cash flows for 2004.
34
A summary of the significant effects of the restatement is as follows:
YEAR ENDED DECEMBER 31, 2004
----------------------------
AS PREVIOUSLY
AS RESTATED REPORTED
----------- -------------
(IN MILLIONS)
STATEMENTS OF CONSOLIDATED INCOME:
Revenues .......................... $6,472 $6,983
Expenses: Natural gas ............. 5,013 5,524
Total Expenses .................... 6,079 6,590
AS OF DECEMBER 31, 2004
---------------------------
AS PREVIOUSLY
AS RESTATED REPORTED
----------- -------------
(IN MILLIONS)
CONSOLIDATED BALANCE SHEETS:
Accounts receivable, net .................... 545 613
Total current assets ........................ 1,719 1,785
Total assets ................................ 7,467 7,533
Accounts payable ............................ 733 799
Total current liabilities ................... 1,595 1,661
Total liabilities and stockholder's equity .. 7,467 7,533
35
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder of
CenterPoint Energy Resources Corp.
Houston, Texas
We have audited the accompanying consolidated balance sheets of CenterPoint
Energy Resources Corp. and subsidiaries (the Company) as of December 31, 2004
and 2003, and the related consolidated statements of income, comprehensive
income, cash flows, and stockholder's equity for each of the three years in the
period ended December 31, 2004. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audits included consideration of internal control over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of CenterPoint Energy
Resources Corp. and subsidiaries at December 31, 2004 and 2003, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2004 in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 13 to the consolidated financial statements, the
accompanying 2004 consolidated financial statements have been restated.
DELOITTE & TOUCHE LLP
Houston, Texas
March 23, 2005 (January 10, 2006 as to the effects of the restatement discussed
in Note 13 to the consolidated financial statements)
36
ITEM 9A. CONTROLS AND PROCEDURES.
DISCLOSURE CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we have
re-evaluated, under the supervision and with the participation of management,
including our principal executive officer and principal financial officer, the
effectiveness of our disclosure controls and procedures (as such term is defined
in Rule 13(a)-15(e) under the Securities Exchange Act of 1934, as amended) 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,
solely because of the material weakness in internal control over financial
reporting described below, our disclosure controls and procedures were not
effective as of December 31, 2004. This conclusion is different than the
conclusion disclosed in the original filing of our Annual Report on Form 10-K
for the year ended December 31, 2004 in which management concluded that our
disclosure controls and procedures were effective. As a result of the material
weakness described below, which was identified subsequent to the original filing
of our Annual Report on Form 10-K for the year ended December 31, 2004,
management has re-evaluated the effectiveness of our disclosure controls and
procedures.
We determined that, during 2004, certain transactions involving purchases
and sales of natural gas among divisions within our Natural Gas Distribution
segment were not properly eliminated in the consolidated financial statements.
Consequently, revenues and natural gas expenses during 2004 were each overstated
by approximately $511 million and management concluded that a restatement of the
2004 consolidated financial statements was necessary to correct this error.
Subsequent to the period covered by this report, in connection with the
discovery of the error described above and the conclusion that we had a material
weakness in our internal control over financial reporting related to ineffective
controls over the process of eliminating certain interdivision purchases and
sales of natural gas within our Natural Gas Distribution segment in the
consolidation process, we improved procedures related to the recording and
reporting of purchases and sales of natural gas, including increased review and
approval controls by senior financial personnel over the personnel that will
prepare the accruals and enhanced analysis of the recorded activity, including
ensuring that intercompany activity is properly eliminated in consolidation.
There has been no change in our internal control over financial reporting
that occurred during the three months ended December 31, 2004 that has
materially affected, or is reasonably likely to materially affect, our internal
control over financial reporting. However, subsequent to the date of filing our
original Annual Report on Form 10-K for the fiscal year ended December 31, 2004,
we took the remedial action described above.
37
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements.
Statements of Consolidated Income for the Three Years Ended
December 31, 2004 (as restated)................................. 10
Statements of Consolidated Comprehensive Income for the Three Years
Ended December 31, 2004......................................... 11
Consolidated Balance Sheets at December 31, 2004 and 2003 (as
restated)....................................................... 12
Statements of Consolidated Cash Flows for the Three Years Ended
December 31, 2004 (as restated)................................. 13
Statements of Consolidated Stockholder's Equity for the Three Years
Ended December 31, 2004......................................... 14
Notes to Consolidated Financial Statements......................... 15
Report of Independent Registered Public Accounting Firm............ 36
(a)(2) Financial Statement Schedules for the Three Years Ended
December 31, 2004.
Report of Independent Registered Public Accounting Firm............ 39
II--Qualifying Valuation Accounts.................................. 40
The following schedules are omitted because of the absence of the
conditions under which they are required or because the required information is
included in the financial statements:
I, III, IV and V.
(a)(3) Exhibits.
See Index of Exhibits beginning on page 42.
38
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder of
CenterPoint Energy Resources Corp.
Houston, Texas
We have audited the consolidated financial statements of CenterPoint Energy
Resources Corp. and subsidiaries (the Company) as of December 31, 2004 and 2003,
and for each of the three years in the period ended December 31, 2004, and have
issued our report thereon dated March 23, 2005, January 10, 2006, as to the
effects of the restatement discussed in Note 13 (which report expresses an
unqualified opinion and includes explanatory paragraph relating to the
restatement discussed in Note 13 to the consolidated financial statements); such
report is included elsewhere in this Form 10-K/A. Our audits also included the
consolidated financial statement schedule of the Company listed in the index at
Item 15 (a)(2). This consolidated financial statement schedule is the
responsibility of the Company's management. Our responsibility is to express an
opinion based on our audits. In our opinion, such consolidated financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly, in all material
respects, the information set forth therein.
DELOITTE & TOUCHE LLP
Houston, Texas
March 23, 2005
39
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
SCHEDULE II -- QUALIFYING VALUATION ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2004
COLUMN A COLUMN B COLUMN C ADDITIONS COLUMN D COLUMN E
----------- ---------- ----------------------- ----------- ----------
BALANCE AT CHARGED TO DEDUCTIONS BALANCE AT
BEGINNING CHARGED OTHER FROM END OF
DESCRIPTION OF PERIOD TO INCOME ACCOUNTS(1) RESERVES(2) PERIOD
----------- ---------- --------- ----------- ----------- ----------
(IN THOUSANDS)
Year Ended December 31, 2004:
Accumulated provisions:
Uncollectible accounts receivable ......... $27,975 $ 26,017 $ -- $26,059 $27,933
Deferred tax asset valuation allowance .... 73,248 (67,428) 14,114 -- 19,934
Year Ended December 31, 2003:
Accumulated provisions:
Uncollectible accounts receivable ......... 19,568 23,713 -- 15,306 27,975
Deferred tax asset valuation allowance .... 82,880 (9,632) -- -- 73,248
Year Ended December 31, 2002:
Accumulated provisions:
Uncollectible accounts receivable ......... 33,047 15,391 -- 28,870 19,568
Deferred tax asset valuation allowance .... 14,999 67,881 -- -- 82,880
- ----------
(1) Charges to other accounts represent changes in presentation to reflect
state tax attributes net of federal tax benefit as well as to reflect
amounts that were netted against related attribute balances in prior years.
(2) Deductions from reserves represent losses or expenses for which the
respective reserves were created. In the case of the uncollectible accounts
reserve, such deductions are net of recoveries of amounts previously
written off.
40
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, in the City of
Houston, the State of Texas, on the 10th day of January, 2006.
CENTERPOINT ENERGY RESOURCES CORP.
(Registrant)
By: /s/ DAVID M. MCCLANAHAN
------------------------------------
David M. McClanahan
President and Chief Executive
Officer
41
CENTERPOINT ENERGY RESOURCES CORP.
EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K/A
FOR FISCAL YEAR ENDED DECEMBER 31, 2004
INDEX OF EXHIBITS
Exhibits included with this report are designated by a cross (+); exhibits
previously filed with our Annual Report on Form 10-K for the fiscal year ended
December 31, 2004 as filed on March 24, 2005 are designated by two crosses (++);
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
- ------- -------------------------------------- -------------------------------- ------------ -----------
2(a)(1) -- Agreement and Plan of Merger HI's Form 8-K dated August 11, 1-7629 2
among the Company, HL&P, HI 1996
Merger, Inc. and NorAm dated
August 11, 1996
2(a)(2) -- Amendment to Agreement and Registration Statement on Form 333-11329 2(c)
Plan of Merger among the S-4
Company, HL&P, HI Merger,
Inc. and NorAm dated August
11, 1996
2(b) -- Agreement and Plan of Merger Registration Statement on Form 333-54526 2
dated December 29, 2000 S-3
merging Reliant Resources
Merger Sub, Inc. with and
into Reliant Energy Services,
Inc.
3(a)(1) -- Certificate of Incorporation Form 10-K for the year ended 1-3187 3(a)(1)
of RERC Corp. December 31, 1997
3(a)(2) -- Certificate of Merger merging Form 10-K for the year ended 1-3187 3(a)(2)
former NorAm Energy Corp. December 31, 1997
with and into HI Merger, Inc.
dated August 6, 1997
3(a)(3) -- Certificate of Amendment Form 10-K for the year ended 1-3187 3(a)(3)
changing the name to Reliant December 31, 1998
Energy Resources Corp.
3(a)(4) -- Certificate of Amendment Form 10-Q for the quarter ended 1-13265 3(a)(4)
changing the name to June 30, 2003
CenterPoint Energy Resources
Corp.
3(b) -- Bylaws of RERC Corp. Form 10-K for the year ended 1-3187 3(b)
December 31, 1997
4(a)(1) -- Indenture, dated as of NorAm's Form 10-K for the year 1-13265 4.14
December 1, 1986, between ended December 31, 1986
NorAm and Citibank, N.A., as
Trustee
4(a)(2) -- First Supplemental Indenture Form 10-K for the year ended 1-3187 4(a)(2)
to Exhibit 4(a)(1) dated as December 31, 1997
of September 30, 1988
4(a)(3) -- Second Supplemental Indenture Form 10-K for the year ended 1-3187 4(a)(3)
to Exhibit 4(a)(1) dated as December 31, 1997
of November 15, 1989
4(a)(4) -- Third Supplemental Indenture Form 10-K for the year ended 1-3187 4(a)(4)
to Exhibit 4(a)(1) dated as December 31, 1997
of August 6, 1997
4(b)(1) -- Indenture, dated as of March 31, NorAm's Registration Statement 33-14586 4.20
1987, between NorAm and on Form S-3
Chase Manhattan Bank, N.A.,
as Trustee, authorizing 6%
Convertible Subordinated
Debentures due 2012
4(b)(2) -- Supplemental Indenture to Form 10-K for the year ended 1-3187 4(b)(2)
Exhibit 4(b)(1) dated as of December 31, 1997
August 6, 1997
4(c)(1) -- Form of Indenture between NorAm's Registration Statement 33-64001 4.8
NorAm and The Bank of New on Form S-3
York as Trustee
42
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
- ------- -------------------------------------- -------------------------------- ------------ -----------
4(c)(2) -- Form of First Supplemental NorAm's Form 8-K dated June 10, 1-13265 4.01
Indenture to Exhibit 4(c)(1) 1996
4(c)(3) -- Second Supplemental Indenture Form 10-K for the year ended 1-3187 4(d)(3)
to Exhibit 4(c)(1) dated as December 31, 1997
of August 6, 1997
4(d) -- Indenture, dated as of Registration Statement on Form 333-41017 4.1
December 1, 1997, between S-3
RERC Corp. and Chase Bank of
Texas, National Association
4(e)(1) -- Indenture, dated as of Form 8-K dated February 5, 1998 1-13265 4.1
February 1, 1998, between
RERC Corp. and Chase Bank of
Texas, National Association,
as Trustee
4(e)(2) -- Supplemental Indenture No. 1, Form 8-K dated February 5, 1998 1-13265 4.2
dated as of February 1, 1998,
providing for the issuance of
RERC Corp.'s 6 1/2%
Debentures due February 1,
2008
4(e)(3) -- Supplemental Indenture No. 2, Form 8-K dated November 9, 1998 1-13265 4.1
dated as of November 1, 1998,
providing for the issuance of
RERC Corp.'s 6 3/8% Term
Enhanced ReMarketable
Securities
4(e)(4) -- Supplemental Indenture No. 3, Registration Statement on Form 333-49162 4.2
dated as of July 1, 2000, S-4
providing for the issuance of
RERC Corp.'s 8.125% Notes due
2005
4(e)(5) -- Supplemental Indenture No. 4, Form 8-K dated February 21, 2001 1-13265 4.1
dated as of February 15,
2001, providing for the
issuance of RERC Corp.'s
7.75% Notes due 2011
4(e)(6) -- Supplemental Indenture No. 5, Form 8-K dated March 18, 2003 1-13265 4.1
dated as of March 25,
2003, providing for the
issuance of CERC Corp.'s
7.875% Senior Notes due 2013
4(e)(7) -- Supplemental Indenture No. 6, Form 8-K dated April 7, 2003 1-13265 4.2
dated as of April 14,
2003, providing for the
issuance of CERC Corp.'s
7.875% Senior Notes due 2013
4(e)(8) -- Supplemental Indenture No. 7, Form 8-K dated October 29, 2003 1-13265 4.2
dated as of November 3,
2003, providing for the
issuance of CERC Corp.'s
5.95% Senior Notes due 2014
4(f) -- $250,000,000 Credit Agreement, Form 8-K dated March 31, 2004 1-13265 4.1
dated as of March 23, 2004,
among CERC Corp., as
borrower, and the Initial
Lenders named therein,
as Initial Lenders
43
There have not been filed as exhibits to this Form 10-K/A certain long-term
debt instruments, including indentures, under which the total amount of
securities do not exceed 10% of the total assets of CERC. CERC hereby agrees to
furnish a copy of any such instrument to the SEC upon request.
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
- ------- -------------------------------------- -------------------------------- ------------ -----------
10(a) -- Service Agreement by and NorAm's Form 10-K for the year 1-13265 10.20
between Mississippi River ended December 31, 1989
Transmission Corporation and
Laclede Gas Company dated
August 22, 1989
++12 -- Computation of Ratios of Earnings
to Fixed Charges
+23 -- Consent of Deloitte & Touche
LLP
+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
44