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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(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
Originated Preferred Securities New York Stock Exchange
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]
The aggregate market value of the common equity held by non-affiliates as
of June 30, 2004: None
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TABLE OF CONTENTS
PAGE
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PART I
Item 1. Business..................................................................... 1
Item 2. Properties................................................................... 14
Item 3. Legal Proceedings............................................................ 14
Item 4. Submission of Matters to a Vote of Security Holders.......................... 14
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities........................................ 14
Item 6. Selected Financial Data...................................................... 15
Item 7. Management's Narrative Analysis of Results of Operations..................... 15
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................... 23
Item 8. Financial Statements and Supplementary Data.................................. 26
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure......................................................... 52
Item 9A. Controls and Procedures...................................................... 52
Item 9B. Other Information............................................................ 52
PART III
Item 10. Directors and Executive Officers of the Registrant........................... 52
Item 11. Executive Compensation....................................................... 52
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.................................................. 52
Item 13. Certain Relationships and Related Transactions............................... 52
Item 14. Principal Accountant Fees and Services....................................... 53
PART IV
Item 15. Exhibits and Financial Statement Schedules................................... 53
i
We meet the conditions specified in General Instruction I(1)(a) and (b) of
Form 10-K and are thereby permitted to use the reduced disclosure format for
wholly owned subsidiaries of reporting companies specified therein. Accordingly,
we have omitted from this report the information called for by Item 4
(Submission of Matters to a Vote of Security Holders), Item 10 (Directors and
Executive Officers of the Registrant), Item 11 (Executive Compensation), Item 12
(Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters) and Item 13 (Certain Relationships and Related
Transactions) of Form 10-K. In lieu of the information called for by Item 6
(Selected Financial Data) and Item 7 (Management's Discussion and Analysis of
Financial Condition and Results of Operations) of Form 10-K, we have included
under Item 7 a Management's Narrative Analysis of the Results of Operations to
explain the reasons for material changes in the amount of revenue and expense
items between 2002, 2003 and 2004.
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 this report.
You should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular
statement, and we undertake no obligation to publicly update or revise any
forward-looking statements.
ii
PART I
ITEM 1. BUSINESS
OUR BUSINESS
GENERAL
We own gas distribution systems serving approximately 3 million customers
in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Through
wholly owned subsidiaries, we also own two interstate natural gas pipelines and
gas gathering systems, provide various ancillary services, and offer variable
and fixed price physical natural gas supplies to commercial and industrial
customers and natural gas distributors. References to "we," "us," and "our" mean
CenterPoint Energy Resources Corp. (CERC Corp., together with our subsidiaries,
CERC). We are an indirect wholly owned subsidiary of CenterPoint Energy, Inc.
(CenterPoint Energy), a public utility holding company.
Our reportable business segments are Natural Gas Distribution, Pipelines
and Gathering and Other Operations.
CenterPoint Energy is a registered public utility holding company under
the Public Utility Holding Company Act of 1935, as amended (1935 Act). The 1935
Act and related rules and regulations impose a number of restrictions on the
activities of CenterPoint Energy and those of its subsidiaries. The 1935 Act,
among other things, limits the ability of CenterPoint Energy and its 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.
Our principal executive offices are located at 1111 Louisiana, Houston,
Texas 77002 (telephone number: 713-207-1111).
We make available free of charge on our parent company's Internet website
our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports
on Form 8-K and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after we electronically file such reports with, or
furnish them to, the Securities and Exchange Commission (SEC). Our parent
company's website address is www.centerpointenergy.com.
NATURAL GAS DISTRIBUTION
Local Distribution Companies
Our natural gas distribution business engages in intrastate natural gas
sales to, and natural gas transportation for, residential, commercial and
industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma
and Texas through three unincorporated divisions: Houston Gas, Minnesota Gas and
Southern Gas Operations. In an effort to increase brand recognition, the naming
conventions of our three unincorporated divisions were changed in 2004.
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. These operations
are regulated as natural gas utility operations in the jurisdictions served by
these divisions.
Houston Gas provides natural gas distribution services to approximately
1,030,000 customers in over 100 communities in the Houston metropolitan area In
2004, approximately 99% of Houston Gas' total throughput was attributable to
retail sales and approximately 1% was attributable to transportation services.
Minnesota Gas provides natural gas distribution services to approximately
750,000 customers in over 240 communities. The largest metropolitan area served
by Minnesota Gas is Minneapolis. In 2004, approximately 91% of Minnesota Gas'
total throughput was attributable to retail sales and approximately 9% was
attributable to transportation services. Minnesota Gas also provides unregulated
services consisting of heating, ventilating and air
1
conditioning (HVAC) equipment and appliance repair, sales of HVAC, water heating
and hearth equipment and home security monitoring.
Southern Gas Operations provides natural gas distribution services to
approximately 1,260,000 customers in Arkansas, Louisiana, Mississippi, Oklahoma
and Texas. The largest metropolitan areas served by Southern Gas Operations are
Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi; Lawton,
Oklahoma; and Laredo, Texas. In 2004, approximately 72% of Southern Gas
Operations' total throughput was attributable to retail sales and approximately
28% was attributable to transportation services.
The demand for intrastate natural gas sales to, and natural gas
transportation for, residential, commercial and industrial customers is
seasonal. In 2004, approximately 70% of the total throughput of our local
distribution companies' business occurred in the first and fourth quarters.
These patterns reflect the higher demand for natural gas for heating purposes
during those periods.
Supply and Transportation. In 2004, Houston Gas purchased virtually all of
its natural gas supply pursuant to contracts, with remaining terms varying from
a few months to two years. Houston Gas' major suppliers in 2004 included
American Electric Power Company (50% of supply volumes) and Kinder Morgan Texas
Pipeline (27%). Numerous other suppliers provided the remaining 23% of Houston
Gas' natural gas supply requirements. Houston Gas transports its natural gas
supplies through various interstate and intrastate pipelines under contracts
with remaining terms varying from one to five years.
In 2004, Minnesota Gas purchased virtually all of its natural gas supply
pursuant to contracts, with remaining terms varying from a few months to four
years. Minnesota Gas' major suppliers in 2004 included BP Canada Energy
Marketing (61% of supply volumes), Occidental Energy Marketing (6%), Tenaska
Marketing Ventures (6%), Prairielands Energy Marketing (4%) and Oneok Energy
Services Company (4%). Numerous other suppliers provided the remaining 19% of
Minnesota Gas' natural gas supply requirements. Minnesota Gas transports its
natural gas supplies through various interstate pipelines under contracts with
remaining terms varying from one to eight years.
In 2004, Southern Gas Operations purchased virtually all of its natural
gas supply pursuant to contracts, with remaining terms varying from a few months
to five years. Southern Gas Operations' major suppliers in 2004 included BP
Energy Company (23% of supply volumes), CenterPoint Energy Gas Services (CEGS),
one of our subsidiaries, (18%), Entergy-Koch, LP (12%), Oneok Energy Marketing
and Trading LLC (8%), American Electric Power Company (6%) and Conoco Phillips
Company (5%). Numerous other suppliers provided the remaining 28% of Southern
Gas Operations' natural gas supply requirements. Southern Gas Operations
transports its natural gas supplies through various intrastate and interstate
pipelines including CenterPoint Energy's pipeline subsidiary.
Generally, the regulations of the states in which our natural gas
distribution business operates allow us to pass through changes in the costs of
natural gas to our customers under purchased gas adjustment provisions in our
tariffs.
Minnesota Gas and Southern Gas Operations use various leased or owned
natural gas storage facilities to meet peak-day requirements and to manage the
daily changes in demand due to changes in weather. Minnesota Gas also
supplements contracted supplies and storage from time to time with stored
liquefied natural gas and propane-air plant production.
Minnesota Gas owns and operates an underground storage facility with a
capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of 2.1 Bcf
available for use during a normal heating season and a maximum daily withdrawal
rate of 50 million cubic feet (MMcf). It also owns nine propane-air plants with
a total capacity of 204 MMcf per day and on-site storage facilities for 12
million gallons of propane (1.0 Bcf gas equivalent). Minnesota Gas owns
liquefied natural gas plant facilities with a 12 million-gallon liquefied
natural gas storage tank (1.0 Bcf gas equivalent) and a send-out capability of
72 MMcf per day.
On an ongoing basis, we enter into contracts to provide sufficient
supplies and pipeline capacity to meet our customer requirements. However, it is
possible for limited service disruptions of interruptible customers' load to
occur from time to time due to weather conditions, transportation constraints
and other events. As a result of these
2
factors, supplies of natural gas may become unavailable from time to time, or
prices may increase rapidly in response to temporary supply constraints or other
factors.
Non-Rate Regulated Gas Sales and Services
We offer variable and fixed priced physical natural gas supplies to
commercial and industrial customers and natural gas distributors through a
number of subsidiaries, primarily CEGS. In 2004, CEGS marketed approximately 579
Bcf (including 134 Bcf to affiliates) of natural gas, transportation and related
energy services to more than 6,000 customers which varied in size from small
commercial to large utility companies in the central regions of the United
States. These customers are served from offices located in Illinois, Louisiana,
Minnesota, Missouri, Texas and Wisconsin. The business has three operational
functions: wholesale, retail and intrastate pipelines further described below.
Wholesale Operations. CEGS offers a portfolio of physical delivery
services and financial products designed to meet wholesale customers' supply and
price risk management needs.
Retail Operations. CEGS also offers a variety of natural gas management
services to smaller commercial and industrial customers including load
forecasting, supply acquisition, daily swing volume management, invoice
consolidation, storage asset management, firm and interruptible transportation
administration and forward price management. CEGS manages transportation
contracts and energy supply for retail customers in ten states.
Intrastate Pipeline Operations. Another wholly owned subsidiary of ours
owns and operates approximately 210 miles of intrastate pipeline in Louisiana
and Texas. This subsidiary provides bundled and unbundled merchant and
transportation services to shippers and end-users.
CEGS currently operates on over 30 pipelines throughout the central United
States. CEGS maintains a portfolio of long-term natural gas supply contracts and
firm transportation agreements to meet the natural gas requirements of its
customers. CEGS aggregates supply from various producing regions and offer
contracts to buy natural gas with terms ranging from one month to over five
years. In addition, CEGS actively participates in the spot natural gas markets
in an effort to balance daily and monthly purchases and sales obligations. Gas
supply and transportation capabilities are leveraged through contracts for
ancillary services including physical storage and other balancing arrangements.
As described above, CEGS offers its customers a variety of load following
services. In providing these services, CEGS will use its customers' purchase
commitments to forecast and arrange its own supply purchases and transportation
services to serve customers' natural gas requirements. As a result of the
variance between this forecast activity and the actual monthly activity, CEGS
will either have too much supply or too little supply relative to its customers'
purchase commitments. These supply imbalances arise each month as customers'
natural gas requirements are scheduled and corresponding natural gas supplies
are nominated by CEGS for delivery to these customers. CEGS' processes and risk
control environment are designed to measure and value all supply imbalances on a
real time basis to ensure that CEGS' exposure to commodity price and volume risk
is kept to a minimum. The value assigned to these volumetric imbalances is
calculated daily and is known as the aggregate Value at Risk (VaR). In 2004,
CEGS' VaR averaged $0.2 million with a high of $1 million.
The CenterPoint Energy Risk Control policy, governed by the Risk Oversight
Committee, defines authorized and prohibited trading instruments and volumetric
trading limits. CEGS is a physical marketer of natural gas and uses a variety of
tools, including pipeline and storage capacity, financial instruments and
physical commodity purchase contracts to support its sales. The CEGS business
optimizes its use of these various tools to minimize its supply costs and does
not engage in proprietary or speculative commodity trading. The low VaR limits
within which CEGS operates are consistent with its operational objective of
matching its aggregate sales obligations (including the swing associated with
load following services) with its supply portfolio in a manner that minimizes
its total cost of supply.
3
Assets
As of December 31, 2004, we owned approximately 65,000 linear miles of gas
distribution mains, varying in size from one-half inch to 24 inches in diameter.
Generally, in each of the cities, towns and rural areas we serve, we own the
underground gas mains and service lines, metering and regulating equipment
located on customers' premises and the district regulating equipment necessary
for pressure maintenance. With a few exceptions, the measuring stations at which
we receive gas are owned, operated and maintained by others, and our
distribution facilities begin at the outlet of the measuring equipment. These
facilities, including odorizing equipment, are usually located on the land owned
by suppliers.
Competition
We compete primarily with alternate energy sources such as electricity and
other fuel sources. In some areas, intrastate pipelines, other gas distributors
and marketers also compete directly for gas sales to end-users. In addition, as
a result of federal regulatory changes affecting interstate pipelines, natural
gas marketers operating on these pipelines may be able to bypass our facilities
and market and sell and/or transport natural gas directly to commercial and
industrial customers.
PIPELINES AND GATHERING
Our pipelines and gathering business operates two interstate natural gas
pipelines, as well as gas gathering facilities and also provides operating and
technical services and remote data monitoring and communication services. The
rates charged by interstate pipelines for interstate transportation and storage
services are regulated by the Federal Energy Regulatory Commission (FERC).
We own and operate gas transmission lines primarily located in Arkansas,
Illinois, Louisiana, Missouri, Oklahoma and Texas. Our pipeline operations are
primarily conducted by two wholly owned interstate pipeline subsidiaries which
provide gas transportation and storage services primarily to industrial
customers and local distribution companies:
- CenterPoint Energy Gas Transmission Company (CEGT) is an interstate
pipeline that provides natural gas transportation, natural gas
storage and pipeline services to customers principally in Arkansas,
Louisiana, Oklahoma and Texas.
- CenterPoint Energy -- Mississippi River Transmission Corporation
(MRT) is an interstate pipeline that provides natural gas
transportation, natural gas storage and pipeline services to
customers principally in Arkansas and Missouri.
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 CEGT's and MRT's
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.
Our pipeline project management and facility operation services are
provided to affiliates and third parties through a wholly owned pipeline
services subsidiary, CenterPoint Energy Pipeline Services, Inc.
In 2004, approximately 22% of our total operating revenue from pipelines
and gathering was attributable to services provided to Southern Gas Operations
and approximately 9% was attributable to services to Laclede Gas Company
(Laclede), an unaffiliated distribution company that provides natural gas
utility service to the greater St. Louis metropolitan area in Illinois and
Missouri. Services to Southern Gas Operations and Laclede are provided under
several long-term firm storage and transportation agreements. The agreement to
provide services to Laclede
4
expires in 2007. Agreements for firm transportation, no notice transportation
service and storage service in Southern Gas Operations' major service areas
(Arkansas, Louisiana and Oklahoma) have recently been entered into and expire in
2012. The Oklahoma agreements are subject to the approval of the Oklahoma
Corporation Commission (OCC).
Our pipelines and gathering business operations may be affected by changes
in the demand for natural gas, the available supply and relative price of
natural gas in the Midcontinent and Gulf Coast natural gas supply regions and
general economic conditions.
Assets
We own and operate approximately 8,200 miles of gas transmission lines
primarily located in Missouri, Illinois, Arkansas, Louisiana, Oklahoma and
Texas. We also own and operate six natural gas storage fields with a combined
daily deliverability of approximately 1.2 Bcf per day and a combined working gas
capacity of approximately 59.0 Bcf. We also own a 10% interest in Gulf South
Pipeline Company, LP's Bistineau storage facility. This facility has a total
working gas capacity of 73.8 Bcf and approximately 1.1 Bcf per day of
deliverability. Our storage capacity in the Bistineau facility is 8 Bcf of
working gas with 100 MMcf per day of deliverability. Most of our storage
operations are in north Louisiana and Oklahoma. We also own and operate
approximately 4,300 miles of gathering pipelines that collect, treat and process
natural gas from approximately 200 separate systems located in major producing
fields in Arkansas, Louisiana, Oklahoma and Texas.
Competition
Our pipelines and gathering business competes with other interstate and
intrastate pipelines and gathering companies in the transportation and storage
of natural gas. The principal elements of competition among pipelines are rates,
terms of service, and flexibility and reliability of service. Our pipelines and
gathering business competes indirectly with other forms of energy available to
our customers, including electricity, coal and fuel oils. The primary
competitive factor is price. Changes in the availability of energy and pipeline
capacity, the level of business activity, conservation and governmental
regulations, the capability to convert to alternative fuels, and other factors,
including weather, affect the demand for natural gas in areas we serve and the
level of competition for transportation and storage services. In addition,
competition for our gathering operations is impacted by commodity pricing levels
because of their influence on the level of drilling activity. Both pipeline
services and Service Star compete with other similar service companies based on
market pricing. The principal elements of competition are rates, terms of
service and reliability of services.
OTHER OPERATIONS
In 2004, Other Operations included unallocated corporate costs and
inter-segment eliminations.
FINANCIAL INFORMATION ABOUT SEGMENTS
For financial information about our segments, see Note 12 to our
consolidated financial statements, which note is incorporated herein by
reference.
REGULATION
We are subject to regulation by various federal, state and local
governmental agencies, including the regulations described below.
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
As a subsidiary of a registered public utility holding company, we are
subject to a comprehensive regulatory scheme imposed by the Securities and
Exchange Commission (SEC) in order to protect customers, investors and the
public interest. Although the SEC does not regulate rates and charges under the
1935 Act, it does regulate the structure, financing, lines of business and
internal transactions of public utility holding companies and their system
5
companies. In order to obtain financing, acquire additional public utility
assets or stock, or engage in other significant transactions, we are generally
required to obtain approval from the SEC under the 1935 Act.
CenterPoint Energy received an order from the SEC under the 1935 Act on
June 30, 2003 and supplemental orders thereafter relating to its financing
activities and those of its regulated subsidiaries, including us, as well as
other matters. The orders are effective until June 30, 2005. As of December 31,
2004, the orders generally permitted CenterPoint Energy and its subsidiaries,
including us, to issue securities to refinance indebtedness outstanding at June
30, 2003, and authorized CenterPoint Energy and its subsidiaries, including us,
to issue certain incremental external debt securities and common and preferred
stock through June 30, 2005 in specified amounts, without prior authorization
from the SEC. The orders also contain certain requirements regarding ratings of
CenterPoint Energy's securities, interest rates, maturities, issuance expenses
and use of proceeds. The orders require that we maintain a ratio of common
equity to total capitalization of at least 30%. We intend to file an application
for approval of our post-June 30, 2005 financing activities.
The United States Congress from time to time considers legislation that
would repeal the 1935 Act. We cannot predict at this time whether this
legislation or any variation thereof will be adopted or, if adopted, the effect
of any such law on our business.
FEDERAL ENERGY REGULATORY COMMISSION
The FERC has jurisdiction under the Natural Gas Act and the Natural Gas
Policy Act of 1978, as amended, to regulate the transportation of natural gas in
interstate commerce and natural gas sales for resale in intrastate commerce that
are not first sales. The FERC regulates, among other things, the construction of
pipeline and related facilities used in the transportation and storage of
natural gas in interstate commerce, including the extension, expansion or
abandonment of these facilities. The rates charged by interstate pipelines for
interstate transportation and storage services are also regulated by the FERC.
Our natural gas pipeline subsidiaries may periodically file applications
with the FERC for changes in their generally available maximum rates and charges
designed to allow them to recover their costs of providing service to customers
(to the extent allowed by prevailing market conditions), including a reasonable
rate of return. These rates are normally allowed to become effective after a
suspension period and, in some cases, are subject to refund under applicable law
until such time as the FERC issues an order on the allowable level of rates.
On November 25, 2003, the FERC issued Order No. 2004, the final rule
modifying the Standards of Conduct applicable to electric and natural gas
transmission providers, governing the relationship between regulated
transmission providers and certain of their affiliates. During 2004, the FERC
Order was amended three times. The rule significantly changes and expands the
regulatory burdens of the Standards of Conduct and applies essentially the same
standards to jurisdictional electric transmission providers and natural gas
pipelines. On February 9, 2004, our natural gas pipeline subsidiaries filed
Implementation Plans required under the new rule. Those subsidiaries were
further required to post their Implementation Procedures on their websites by
September 22, 2004, and to be in compliance with the requirements of the new
rule by that date.
STATE AND LOCAL REGULATION
In almost all communities in which we provide natural gas distribution
services, we operate under franchises, certificates or licenses obtained from
state and local authorities. The terms of the franchises, with various
expiration dates, typically range from 10 to 30 years, though franchises in
Arkansas are perpetual. None of our material franchises expire in the near term.
We expect to be able to renew expiring franchises. In most cases, franchises to
provide natural gas utility services are not exclusive.
Substantially all of our retail natural gas sales by our local
distribution divisions are subject to traditional cost-of-service regulation at
rates regulated by the relevant state public utility commissions and, in Texas,
by the Railroad Commission of Texas (Railroad Commission) and municipalities we
serve.
In 2004, the City of Houston, 28 other cities and the Railroad Commission
approved a settlement that increased Houston Gas' base rate and service charge
revenues by approximately $14 million annually.
6
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 OCC approved a settlement that increased Southern
Gas Operations' base rate and service charge revenues in Oklahoma by
approximately $3 million annually.
DEPARTMENT OF TRANSPORTATION
In December 2002, Congress enacted the Pipeline Safety Improvement Act of
2002 (the Act). This legislation applies to our interstate pipelines as well as
our intrastate pipelines and local distribution companies. The legislation
imposes several requirements related to ensuring pipeline safety and integrity.
It requires pipeline and distribution companies to assess the integrity of their
pipeline transmission facilities in areas of high population concentration or
High Consequence Areas (HCA). The legislation further requires companies to
perform remediation activities, in accordance with the requirements of the
legislation, over a 10-year period.
In December 2003, the Department of Transportation Office of Pipeline
Safety issued the final regulations to implement the Act. These regulations
became effective on February 14, 2004 and provided guidance on, among other
things, the areas that should be classified as HCA. Our interstate pipelines
developed and implemented a written pipeline integrity management program in
2004, meeting the Department of Transportation Office of Pipeline Safety
requirement of having the program in place by December 17, 2004.
Our interstate and intrastate pipelines and our natural gas distribution
companies anticipate that compliance with the new regulations will require
increases in both capital and operating cost. The level of expenditures required
to comply with these regulations will be dependent on several factors, including
the age of the facility, the pressures at which the facility operates and the
number of facilities deemed to be located in areas designated as HCA. Based on
our interpretation of the rules and preliminary technical reviews, we anticipate
compliance will require average annual expenditures of approximately $15 to $20
million during the initial 10-year period.
ENVIRONMENTAL MATTERS
Our operations are subject to stringent and complex laws and regulations
pertaining to health, safety and the environment. As an owner or operator of
natural gas pipelines and gas gathering and processing systems, we must comply
with these laws and regulations at the federal, state and local levels. These
laws and regulations can restrict or impact our business activities in many
ways, such as:
7
- restricting the way we can handle or dispose of our wastes;
- limiting or prohibiting construction activities in sensitive areas
such as wetlands, coastal regions, or areas inhabited by endangered
species;
- requiring remedial action to mitigate pollution conditions caused by
our operations, or attributable to former operations; and
- enjoining the operations of facilities deemed in non-compliance with
permits issued pursuant to such environmental laws and regulations.
In order to comply with these requirements, we may need to spend
substantial amounts and devote other resources from time to time to:
- construct or acquire new equipment;
- acquire permits for facility operations;
- modify or replace existing and proposed equipment; and
- clean up or decommission waste disposal areas, fuel storage and
management facilities and other locations and facilities.
Failure to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial requirements, and
the issuance of orders enjoining future operations. Certain environmental
statutes impose strict, joint and several liability for costs required to clean
up and restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.
The trend in environmental regulation is to place more restrictions and
limitations on activities that may affect the environment, and thus there can be
no assurance as to the amount or timing of future expenditures for environmental
compliance or remediation, and actual future expenditures may be different from
the amounts we currently anticipate. We try to anticipate future regulatory
requirements that might be imposed and plan accordingly to remain in compliance
with changing environmental laws and regulations and to minimize the costs of
such compliance.
We do not believe that compliance with federal, state or local
environmental laws and regulations will have a material adverse effect on our
business, financial position or results of operations. In addition, we believe
that the various environmental remediation activities in which we are presently
engaged will not materially interrupt or diminish our operational ability. We
cannot assure you, however, that future events, such as changes in existing
laws, the promulgation of new laws, or the development or discovery of new facts
or conditions will not cause us to incur significant costs. The following is a
discussion of all material environmental and safety laws and regulations that
relate to our operations. We believe that we are in substantial compliance with
all of these environmental laws and regulations.
AIR EMISSIONS
Our operations are subject to the federal Clean Air Act and comparable
state laws and regulations. These laws and regulations regulate emissions of air
pollutants from various industrial sources, including our processing plants and
compressor stations, and also impose various monitoring and reporting
requirements. Such laws and regulations may require that we obtain pre-approval
for the construction or modification of certain projects or facilities expected
to produce air emissions or result in the increase of existing air emissions,
obtain and strictly comply with air permits containing various emissions and
operational limitations, or utilize specific emission control technologies to
limit emissions. Our failure to comply with these requirements could subject us
to monetary penalties, injunctions, conditions or restrictions on operations,
and potentially criminal enforcement actions. We may be required to incur
certain capital expenditures in the future for air pollution control equipment
in connection with obtaining and
8
maintaining operating permits and approvals for air emissions. We believe,
however, that our operations will not be materially adversely affected by such
requirements, and the requirements are not expected to be any more burdensome to
us than to any other similarly situated companies.
WATER DISCHARGES
Our operations are subject to the Federal Water Pollution Control Act of
1972, as amended, also known as the Clean Water Act, and analogous state laws
and regulations. These laws and regulations impose detailed requirements and
strict controls regarding the discharge of pollutants into waters of the United
States. The unpermitted discharge of pollutants, including discharges resulting
from a spill or leak incident, is prohibited. The Clean Water Act and
regulations implemented thereunder also prohibit discharges of dredged and fill
material in wetlands and other waters of the United States unless authorized by
an appropriately issued permit. Any unpermitted release of petroleum or other
pollutants from our pipelines or facilities could result in fines or penalties
as well as significant remedial obligations.
HAZARDOUS WASTE
Our operations generate wastes, including some hazardous wastes, that are
subject to the federal Resource Conservation and Recovery Act (RCRA), and
comparable state laws, which impose detailed requirements for the handling,
storage, treatment and disposal of hazardous and solid waste. RCRA currently
exempts many natural gas gathering and field processing wastes from
classification as hazardous waste. Specifically, RCRA excludes from the
definition of hazardous waste produced waters and other wastes associated with
the exploration, development, or production of crude oil and natural gas.
However, these oil and gas exploration and production wastes are still regulated
under state law and the less stringent non-hazardous waste requirements of RCRA.
Moreover, ordinary industrial wastes such as paint wastes, waste solvents,
laboratory wastes, and waste compressor oils may be regulated as hazardous
waste. The transportation of natural gas in pipelines may also generate some
hazardous wastes that are subject to RCRA or comparable state law requirements.
LIABILITY FOR REMEDIATION
The Comprehensive Environmental Response, Compensation and Liability Act
of 1980, as amended (CERCLA), also known as "Superfund," and comparable state
laws impose liability, without regard to fault or the legality of the original
conduct, on certain classes of persons responsible for the release of hazardous
substances into the environment. Such classes of persons include the current and
past owners or operators of sites where a hazardous substance was released, and
companies that disposed or arranged for disposal of hazardous substances at
offsite locations such as landfills. Although petroleum as well as natural gas
is excluded from CERCLA's definition of "hazardous substance," in the course of
our ordinary operations we generate wastes that may fall within the definition
of a "hazardous substance." CERCLA authorizes the United States Environmental
Protection Agency (EPA) and, in some cases, third parties to take actions in
response to threats to the public health or the environment and to seek to
recover from the responsible classes of persons the costs they incur. Under
CERCLA, we could be subject to joint and several liability for the costs of
cleaning up and restoring sites where hazardous substances have been released,
for damages to natural resources, and for the costs of certain health studies.
LIABILITY FOR PREEXISTING CONDITIONS
Hydrocarbon Contamination. We and certain of our 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
9
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. We
believe the ultimate cost associated with resolving this matter will not have a
material impact on our financial condition or results of operations.
Manufactured Gas Plant Sites. We and our predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, we have completed
remediation on two sites, other than ongoing monitoring and water treatment.
There are five remaining sites in our Minnesota service territory. We believe
that we have no liability with respect to two of these sites.
At December 31, 2004, we 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 remediation methods used. We have utilized an environmental
expense tracker mechanism in our rates in Minnesota to recover estimated costs
in excess of insurance recovery. As of December 31, 2004, we have collected or
accrued $13 million from insurance companies and ratepayers to be used for
future environmental remediation.
In addition to the Minnesota sites, the EPA and other regulators have
investigated MGP sites that we owned or operated or may have been owned or
operated by one of our former affiliates. We have 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 our
former affiliates or divisions. We have also been identified as a PRP by the
State of Maine for a site that is the subject of one of the lawsuits. We are
investigating details regarding these sites and the range of environmental
expenditures for potential remediation. However, we believe we are not liable as
a former owner or operator of those sites under CERCLA and applicable state
statutes, and are vigorously contesting those suits and our designation as a
PRP.
Mercury Contamination. Our pipeline and distribution operations have in
the past employed elemental mercury in measuring and regulating equipment. It is
possible that small amounts of mercury may have been spilled in the course of
normal maintenance and replacement operations and that these spills may have
contaminated the immediate area with elemental mercury. We have found this type
of contamination at some sites in the past, and we have conducted remediation at
these sites. It is possible that other contaminated sites may exist and that
remediation costs may be incurred for these sites. Although the total amount of
these costs cannot be known at this time, based on our experience and that of
others in the natural gas industry to date and on the current regulations
regarding remediation of these sites, we believe that the costs of any
remediation of these sites will not be material to our financial condition,
results of operations or cash flows.
Other Environmental. From time to time, we have received notices from
regulatory authorities or others regarding our status as a PRP in connection
with sites found to require remediation due to the presence of environmental
contaminants. Although their ultimate outcome cannot be predicted at this time,
we do not believe, based on our experience to date, that these matters, either
individually or in the aggregate, will have a material adverse effect on our
financial condition, results of operations or cash flows.
EMPLOYEES
As of December 31, 2004, we had 5,194 full-time employees. The following
table sets forth the number of our employees by business segment as of December
31, 2004:
NUMBER REPRESENTED BY
UNIONS OR OTHER
COLLECTIVE BARGAINING
BUSINESS SEGMENT NUMBER GROUPS
- ---------------------------------------------------- ------ ---------------------
Natural Gas Distribution............................ 4,517 1,538
Pipelines and Gathering............................. 677 --
------ -----
Total............................................. 5,194 1,538
====== =====
10
As of December 31, 2004, approximately 30% of our employees are subject to
collective bargaining agreements. Four of these agreements, covering
approximately 15% of our employees, have expired or will expire in 2005.
RISK FACTORS
PRINCIPAL RISK FACTORS ASSOCIATED WITH OUR BUSINESSES
RATE REGULATION OF OUR BUSINESS MAY DELAY OR DENY OUR ABILITY TO EARN A
REASONABLE RETURN AND FULLY RECOVER OUR COSTS.
Our rates for our local distribution companies are regulated by certain
municipalities and state commissions based on an analysis of our invested
capital and our expenses incurred in a test year. Thus, the rates that we are
allowed to charge may not match our expenses at any given time. While rate
regulation in the applicable jurisdictions is, generally, premised on providing
an opportunity to recover reasonable and necessary operating expenses and to
earn a reasonable return on invested capital, there can be no assurance that the
regulatory process in which rates are determined will always result in rates
that will produce full recovery of our costs and enable us to earn a reasonable
return on our invested capital.
OUR BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, AND OUR
PIPELINES AND GATHERING BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN
THE TRANSPORTATION, STORAGE, GATHERING, TREATING AND PROCESSING OF NATURAL
GAS.
We compete primarily with alternate energy sources such as electricity and
other fuel sources. In some areas, intrastate pipelines, other natural gas
distributors and marketers also compete directly with us for natural gas sales
to end-users. In addition, as a result of federal regulatory changes affecting
interstate pipelines, natural gas marketers operating on these pipelines may be
able to bypass our facilities and market, sell and/or transport natural gas
directly to commercial and industrial customers. Any reduction in the amount of
natural gas we market, sell or transport as a result of competition may have an
adverse impact on our results of operations, financial condition and cash flows.
Our two interstate pipelines and our gathering systems compete with other
interstate and intrastate pipelines and gathering systems in the transportation
and storage of natural gas. The principal elements of competition are rates,
terms of service, and flexibility and reliability of service. They also compete
indirectly with other forms of energy, including electricity, coal and fuel
oils. The primary competitive factor is price. The actions of our competitors
could lead to lower prices, which may have an adverse impact on our results of
operations, financial condition and cash flows.
OUR NATURAL GAS DISTRIBUTION BUSINESS IS SUBJECT TO FLUCTUATIONS IN
NATURAL GAS PRICING LEVELS.
We are subject to risk associated with price movements of natural gas.
Movements in natural gas prices might affect our ability to collect balances due
from our customers and, on the regulated side, could create the potential for
uncollectible accounts expense to exceed the recoverable levels built into our
tariff rates. In addition, a sustained period of high natural gas prices could
apply downward demand pressure on natural gas consumption in the areas in which
we operate and increase the risk that our suppliers or customers fail or are
unable to meet their obligations. Additionally, increasing gas prices could
create the need for us to provide collateral in order to purchase gas.
IF WE WERE TO FAIL TO EXTEND A CONTRACT WITH ONE OF OUR SIGNIFICANT
PIPELINE CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON OUR OPERATIONS.
Our contract with Laclede Gas Company, one of our pipeline customers, is
currently scheduled to expire in 2007. To the extent the pipeline is unable to
extend this contract or the contract is renegotiated at rates substantially less
than the rates provided in the current contract, there could be an adverse
effect on our results of operations, financial condition and cash flows.
A DECLINE IN OUR CREDIT RATING COULD RESULT IN US HAVING TO PROVIDE
COLLATERAL IN ORDER TO PURCHASE GAS.
If our credit rating were to decline, we might be required to post cash
collateral in order to purchase natural gas. If a credit rating downgrade and
the resultant cash collateral requirement were to occur at a time when we were
11
experiencing significant working capital requirements or otherwise lacked
liquidity, we might be unable to obtain the necessary natural gas to meet our
contractual distribution obligations, and our results of operations, financial
condition and cash flows would be adversely affected.
OUR INTERSTATE PIPELINES' AND NATURAL GAS GATHERING AND PROCESSING
BUSINESS' REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO FLUCTUATIONS
IN THE SUPPLY OF GAS.
Our interstate pipelines and natural gas gathering and processing
businesses largely rely on gas sourced in the various supply basins located in
the Midcontinent region of the United States. To the extent the availability of
this supply is substantially reduced, it could have an adverse effect on our
results of operations, financial condition and cash flows.
OUR REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.
A substantial portion of our revenues are derived from natural gas sales
and transportation. Thus, our revenues and results of operations are subject to
seasonality, weather conditions and other changes in natural gas usage, with
revenues being higher during the winter months.
RISK FACTORS ASSOCIATED WITH OUR CONSOLIDATED FINANCIAL CONDITION
IF WE ARE UNABLE TO ARRANGE FUTURE FINANCINGS ON ACCEPTABLE TERMS, OUR
ABILITY TO REFINANCE EXISTING INDEBTEDNESS COULD BE LIMITED.
As of December 31, 2004, we had $2.4 billion of outstanding indebtedness.
As of March 11, 2005, approximately $518 million principal amount of this debt
must be paid through 2006. The success of our future financing efforts may
depend, at least in part, on:
- general economic and capital market conditions;
- credit availability from financial institutions and other lenders;
- investor confidence in us and the markets in which we operate;
- maintenance of acceptable credit ratings by us and by CenterPoint
Energy;
- market expectations regarding our future earnings and probable cash
flows;
- market perceptions of our ability to access capital markets on
reasonable terms;
- provisions of relevant tax and securities laws; and
- our ability to obtain approval of specific financing transactions
under the 1935 Act.
Our current credit ratings are discussed in "Management's Narrative
Analysis of the Results of Operations -- Liquidity -- Impact on Liquidity of a
Downgrade in Credit Ratings" in Item 7 of Part II of this report. We cannot
assure you that these credit ratings will remain in effect for any given period
of time or that one or more of these ratings will not be lowered or withdrawn
entirely by a rating agency. We note that these credit ratings are not
recommendations to buy, sell or hold our securities. Each rating should be
evaluated independently of any other rating. Any future reduction or withdrawal
of one or more of our credit ratings could have a material adverse impact on our
ability to access capital on acceptable terms.
THE FINANCIAL CONDITION AND LIQUIDITY OF OUR PARENT COMPANY COULD AFFECT OUR
ACCESS TO CAPITAL, OUR CREDIT STANDING AND OUR FINANCIAL CONDITION.
Our ratings and credit may be impacted by CenterPoint Energy's credit
standing. As of March 11, 2005, CenterPoint Energy and its other subsidiaries
have approximately $1.3 billion principal amount of debt required to
12
be paid through 2006. This amount excludes amounts related to capital leases,
securitization debt and indexed debt securities obligations. We cannot assure
you that CenterPoint Energy and its other subsidiaries will be able to pay or
refinance these amounts. If CenterPoint Energy were to experience a
deterioration in its credit standing or liquidity difficulties, our access to
credit and our credit ratings could be adversely affected.
WE ARE AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY.
CENTERPOINT ENERGY CAN EXERCISE SUBSTANTIAL CONTROL OVER OUR DIVIDEND POLICY
AND BUSINESS AND OPERATIONS AND COULD DO SO IN A MANNER THAT IS ADVERSE TO
OUR INTERESTS.
We are managed by officers and employees of CenterPoint Energy. Our
management will make determinations with respect to the following:
- our payment of dividends;
- decisions on our financings and our capital raising activities;
- mergers or other business combinations; and
- our acquisition or disposition of assets.
There are no contractual restrictions on our ability to pay dividends to
CenterPoint Energy. Our management could decide to increase our dividends to
CenterPoint Energy to support its cash needs. This could adversely affect our
liquidity. Under the 1935 Act, our ability to pay dividends is restricted by the
SEC's requirement that common equity as a percentage of total capitalization
must be at least 30% after the payment of any dividend. Under our credit
facility and our receivables facility, our ability to pay dividends is
restricted by a covenant that debt as a percentage of total capitalization may
not exceed 60%.
THE USE OF DERIVATIVE CONTRACTS BY US AND OUR SUBSIDIARIES IN THE NORMAL
COURSE OF BUSINESS COULD RESULT IN FINANCIAL LOSSES THAT NEGATIVELY IMPACT
OUR RESULTS OF OPERATIONS AND THOSE OF OUR SUBSIDIARIES.
We use derivative instruments, such as swaps, options, futures and
forwards, to manage our commodity and financial market risks. We could recognize
financial losses as a result of volatility in the market values of these
contracts, or if a counterparty fails to perform. In the absence of actively
quoted market prices and pricing information from external sources, the
valuation of these financial instruments can involve management's judgment or
use of estimates. As a result, changes in the underlying assumptions or use of
alternative valuation methods could affect the reported fair value of these
contracts.
OTHER RISKS
WE, AS A SUBSIDIARY OF CENTERPOINT ENERGY, A HOLDING COMPANY, ARE SUBJECT
TO REGULATION UNDER THE 1935 ACT. THE 1935 ACT AND RELATED RULES AND
REGULATIONS IMPOSE A NUMBER OF RESTRICTIONS ON OUR ACTIVITIES.
CenterPoint Energy and its subsidiaries, including us, are subject to
regulation by the SEC under the 1935 Act. The 1935 Act, among other things,
limits the ability of a holding company and its regulated subsidiaries to issue
debt and equity securities without prior authorization, restricts the source of
dividend payments to current and retained earnings without prior authorization,
regulates sales and acquisitions of certain assets and businesses and governs
affiliated service, sales and construction contracts.
CenterPoint Energy received an order from the SEC under the 1935 Act on
June 30, 2003 relating to its financing activities, which is effective until
June 30, 2005. Although authorized levels of financing, together with current
levels of liquidity, are believed to be adequate during the period the order is
effective, unforeseen events could result in capital needs in excess of
authorized amounts, necessitating further authorization from the SEC. Approval
of filings under the 1935 Act can take extended periods.
We must seek a new financing order under the 1935 Act for approval of our
post-June 30, 2005 financing activities before the current financing order
expires on June 30, 2005. If we are unable to obtain a new financing
13
order, we would generally be unable to engage in any financing transactions,
including the refinancing of existing obligations after June 30, 2005.
The United States Congress from time to time considers legislation that
would repeal the 1935 Act. We cannot predict at this time whether this
legislation or any variation thereof will be adopted or, if adopted, the effect
of any such law on our business.
OUR INSURANCE COVERAGE MAY NOT BE SUFFICIENT. INSUFFICIENT INSURANCE
COVERAGE AND INCREASED INSURANCE COSTS COULD ADVERSELY IMPACT OUR RESULTS
OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.
We currently have general liability and property insurance in place to
cover certain of our facilities in amounts that we consider appropriate. Such
policies are subject to certain limits and deductibles and do not include
business interruption coverage. We cannot assure you that insurance coverage
will be available in the future at current costs or on commercially reasonable
terms or that the insurance proceeds received for any loss of or any damage to
any of our facilities will be sufficient to restore the loss or damage without
negative impact on our results of operations, financial condition and cash
flows.
ITEM 2. PROPERTIES
CHARACTER OF OWNERSHIP
We own our principal properties in fee. Most of our gas mains are located,
pursuant to easements and other rights, on public roads or on land owned by
others.
NATURAL GAS DISTRIBUTION
For information regarding the properties of our Natural Gas Distribution
business segment, please read "Our Business -- Natural Gas Distribution" in Item
1 of this report, which information is incorporated herein by reference.
PIPELINES AND GATHERING
For information regarding the properties of our Pipelines and Gathering
business segment, please read "Our Business -- Pipelines and Gathering" in Item
1 of this report, which information is incorporated herein by reference.
ITEM 3. LEGAL PROCEEDINGS
For a brief description of certain legal and regulatory proceedings
affecting us, please read "Regulation" and "Environmental Matters" in Item 1 of
this report and Notes 3, 9(c) and 9(d) to our consolidated financial statements,
which information is incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The information called for by Item 4 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
All of the 1,000 outstanding shares of CERC Corp.'s common stock are held
by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy.
14
Our ability to pay dividends is restricted by the SEC's requirement that
common equity as a percentage of total capitalization must be at least 30% after
the payment of any dividend. In addition, the SEC restricts our ability to pay
dividends out of capital accounts to the extent current or retained earnings are
insufficient for those dividends.
In 2003, we paid no dividends on our common stock. In 2004, we paid
dividends on our common stock of $12.5 million to Utility Holding, LLC.
ITEM 6. SELECTED FINANCIAL DATA
The information called for by Item 6 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
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.
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.
15
OTHER OPERATIONS
Our Other Operations business segment includes unallocated corporate costs
and inter-segment eliminations.
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 in Item 1 of this report under "Risk
Factors."
16
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.
YEAR ENDED DECEMBER 31,
-----------------------------------
2002 2003 2004
--------- --------- ---------
(IN MILLIONS)
Revenues.......................................................... $ 4,208 $ 5,650 $ 6,983
--------- --------- ---------
Expenses:
Natural gas..................................................... 2,901 4,297 5,524
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 6,590
--------- --------- ---------
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.
17
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 $ 6,684
--------- --------- ---------
Operating Expenses:
Natural gas................................................................ 2,995 4,428 5,631
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 6,462
--------- --------- ---------
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)
18
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 this report.
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.
(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.
19
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 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 " --
20
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 in "Risk Factors."
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.
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.
21
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
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.
22
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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
IMPACT OF CHANGES IN INTEREST RATES AND ENERGY COMMODITY PRICES
We are exposed to various market risks. These risks arise from
transactions entered into in the normal course of business and are inherent in
our consolidated financial statements. Most of the revenues and income from our
business activities are impacted by market risks. Categories of market risk
include exposure to commodity prices through non-trading activities, interest
rates and equity prices. A description of each market risk is set forth below:
- Commodity price risk results from exposures to changes in spot
prices, forward prices and price volatilities of commodities, such
as natural gas and other energy commodities risk.
- Interest rate risk primarily results from exposures to changes in
the level of borrowings and changes in interest rates.
- Equity price risk results from exposures to changes in prices of
individual equity securities.
Management has established comprehensive risk management policies to
monitor and manage these market risks. We manage these risk exposures through
the implementation of our risk management policies and framework. We manage our
exposures through the use of derivative financial instruments and derivative
commodity instrument contracts. During the normal course of business, we review
our hedging strategies and determine the hedging approach we deem appropriate
based upon the circumstances of each situation.
Derivative instruments such as futures, forward contracts, swaps and
options derive their value from underlying assets, indices, reference rates or a
combination of these factors. These derivative instruments include negotiated
23
contracts, which are referred to as over-the-counter derivatives, and
instruments that are listed and traded on an exchange.
Derivative transactions are entered into in our non-trading operations to
manage and hedge certain exposures, such as exposure to changes in gas prices.
We believe that the associated market risk of these instruments can best be
understood relative to the underlying assets or risk being hedged.
INTEREST RATE RISK
We have outstanding long-term debt, mandatory redeemable preferred
securities of a subsidiary trust holding solely our junior subordinated
debentures (trust preferred securities), a bank facility and some lease
obligations which subject us to the risk of loss associated with movements in
market interest rates.
Our floating-rate obligations aggregated $63 million at December 31, 2003.
We had no floating-rate obligations at December 31, 2004.
At both December 31, 2003 and 2004, we had outstanding fixed-rate debt and
trust preferred securities aggregating $2.4 billion in principal amount and
having a fair value of $2.6 billion and $2.7 billion, respectively. These
instruments are fixed-rate and, therefore, do not expose us to the risk of loss
in earnings due to changes in market interest rates (please read Note 6 to our
consolidated financial statements). However, the fair value of these instruments
would increase by approximately $59 million if interest rates were to decline by
10% from their levels at December 31, 2004. In general, such an increase in fair
value would impact earnings and cash flows only if we were to reacquire all or a
portion of these instruments in the open market prior to their maturity.
COMMODITY PRICE RISK FROM NON-TRADING ACTIVITIES
To reduce our commodity price risk from market fluctuations in the
revenues derived from the sale of natural gas and related transportation, we
enter into forward contracts, swaps and options (Non-Trading Energy Derivatives)
in order to hedge some expected purchases of natural gas and sales of natural
gas (a portion of which are firm commitments at the inception of the hedge).
Non-Trading Energy Derivatives are also utilized to fix the price of future
operational gas requirements.
We use derivative instruments as economic hedges to offset the commodity
exposure inherent in our businesses. The stand-alone commodity risk created by
these instruments, without regard to the offsetting effect of the underlying
exposure these instruments are intended to hedge, is described below. We measure
the commodity risk of our Non-Trading Energy Derivatives using a sensitivity
analysis. The sensitivity analysis performed on our Non-Trading Energy
Derivatives measures the potential loss in earnings based on a hypothetical 10%
movement in energy prices. A decrease of 10% in the market prices of energy
commodities from their December 31, 2003 levels would have decreased the fair
value of our Non-Trading Energy Derivatives by $50 million. A decrease of 10% in
the market prices of energy commodities from their December 31, 2004 levels
would have decreased the fair value of our Non-Trading Energy Derivatives by $46
million.
The above analysis of the Non-Trading Energy Derivatives utilized for
hedging purposes does not include the favorable impact that the same
hypothetical price movement would have on our physical purchases and sales of
natural gas to which the hedges relate. Furthermore, the Non-Trading Energy
Derivative portfolio is managed to complement the physical transaction
portfolio, reducing overall risks within limits. Therefore, the adverse impact
to the fair value of the portfolio of Non-Trading Energy Derivatives held for
hedging purposes associated with the hypothetical changes in commodity prices
referenced above would be offset by a favorable impact on the underlying hedged
physical transactions, assuming:
- the Non-Trading Energy Derivatives are not closed out in advance of
their expected term;
- the Non-Trading Energy Derivatives continue to function effectively
as hedges of the underlying risk; and
- as applicable, anticipated underlying transactions settle as
expected.
24
If any of the above-mentioned assumptions ceases to be true, a loss on the
derivative instruments may occur, or the options might be worthless as
determined by the prevailing market value on their termination or maturity date,
whichever comes first. Non-Trading Energy Derivatives designated and effective
as hedges, may still have some percentage which is not effective. The change in
value of the Non-Trading Energy Derivatives that represents the ineffective
component of the hedges is recorded in our results of operations.
CenterPoint Energy has established a Risk Oversight Committee, comprised
of corporate and business segment officers, that oversees commodity price and
credit risk activities, including trading, marketing, risk management services
and hedging activities. The committee's duties are to establish commodity risk
policies, allocate risk capital, approve trading of new products and
commodities, monitor risk positions and ensure compliance with the risk
management policies and procedures and trading limits established by CenterPoint
Energy's board of directors.
Our 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.
25
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,
-------------------------------------------
2002 2003 2004
------------- ------------- -------------
(IN THOUSANDS)
REVENUES............................................... $ 4,207,836 $ 5,649,720 $ 6,983,445
------------- ------------- -------------
EXPENSES:
Natural gas.......................................... 2,900,682 4,296,928 5,524,451
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 6,590,529
------------- ------------- -------------
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
26
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
27
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
-----------------------------
2003 2004
------------- -------------
(IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents............................................ $ 34,447 $ 140,466
Accounts receivable, net............................................. 462,988 612,708
Accrued unbilled revenue............................................. 323,844 502,163
Accounts and notes receivable -- affiliated companies, net........... -- 11,987
Inventory............................................................ 187,226 199,249
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 1,784,671
------------- -------------
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 $ 7,532,951
============= =============
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES:
Short-term borrowings................................................ $ 63,000 $ --
Current portion of long-term debt.................................... -- 366,873
Accounts payable..................................................... 528,394 798,661
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 1,660,560
------------- -------------
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 $ 7,532,951
============= =============
See Notes to the Company's Consolidated Financial Statements
28
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEAR ENDED DECEMBER 31,
----------------------------------------
2002 2003 2004
------------ ------------ ------------
(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) (230,119)
Accounts receivable/payable, affiliates................ (65,688) (3,784) 6,519
Inventory.............................................. 8,762 (51,519) (12,023)
Taxes receivable....................................... (61,512) 29,489 118,387
Accounts payable....................................... 198,045 58,062 273,797
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
29
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
30
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
31
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
========
The Company completed its annual evaluation of goodwill for impairment as
of January 1, 2004 and no impairment was indicated.
32
The Company periodically evaluates long-lived assets, including property,
plant and equipment, goodwill 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 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.
33
(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............................ 160 174
------- -------
Total inventory...................... $ 187 $ 199
======= =======
(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 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
34
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.
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.
35
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.
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.
36
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) 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 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.
37
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.
(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.
38
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 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.
39
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.
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
40
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.
41
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 December December
assets..................................................... 31, 2003 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
42
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.
43
(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%
44
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 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.
45
(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 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
46
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 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.
47
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.
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
48
11. UNAUDITED QUARTERLY INFORMATION
Summarized quarterly financial data 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.................... $ 2,196 $ 1,323 $ 1,219 $ 2,245
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.
49
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....................... 6,681 (1) 306 (2) (4) -- 6,983
Intersegment revenues.................. 3 145 5 (153) --
Depreciation and amortization.......... 143 44 -- -- 187
Operating income (loss)................ 222 180 (9) -- 393
Total assets........................... 4,798 2,637 792 (694) 7,533
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 $ 6,583
Gas transportation.................................. 255 244 306
Energy products and services........................ 96 96 94
--------- --------- ---------
Total............................................. $ 4,208 $ 5,650 $ 6,983
========= ========= =========
50
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.
DELOITTE & TOUCHE LLP
Houston, Texas
March 23, 2005
51
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
DISCLOSURE CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our principal executive officer and principal financial officer, of
the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our principal executive
officer and principal financial officer concluded that our disclosure controls
and procedures were effective as of December 31, 2004 to provide assurance that
information required to be disclosed in our reports filed or submitted under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the Securities and Exchange Commission's rules and forms.
There has been no change in our internal controls over financial reporting
that occurred during the three months ended December 31, 2004 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by Item 10 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
ITEM 11. EXECUTIVE COMPENSATION
The information called for by Item 11 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information called for by Item 12 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by Item 13 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).
52
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Aggregate fees billed to the Company during the fiscal years ending
December 31, 2003 and 2004 by its principal accounting firm, Deloitte & Touche
LLP, are set forth below. These fees do not include certain fees related to
general corporate matters, financial reporting, tax and other fees which have
not been allocated to the Company by CenterPoint Energy.
YEAR ENDED DECEMBER 31,
-----------------------
2003 2004
----------- ---------
Audit fees.............................. $ 864,259 $ 840,408
Audit-related fees...................... 53,935 79,075
----------- ---------
Total audit and audit-related fees. 918,194 919,483
Tax fees................................ -- --
All other fees.......................... -- --
----------- ---------
Total fees......................... $ 918,194 $ 919,483
=========== =========
The Company is not required to have, and does not have, an audit
committee.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements.
Statements of Consolidated Income for the Three Years Ended December 31, 2004............................. 26
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2004............... 27
Consolidated Balance Sheets at December 31, 2004 and 2003................................................. 28
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2004......................... 29
Statements of Consolidated Stockholder's Equity for the Three Years Ended December 31, 2004............... 30
Notes to Consolidated Financial Statements................................................................ 31
Report of Independent Registered Public Accounting Firm................................................... 51
(a)(2) Financial Statement Schedules for the Three Years Ended December 31, 2004.
II--Qualifying Valuation Accounts......................................................................... 54
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 56.
53
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 C
COLUMN A COLUMN B 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.
54
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 24th day of March, 2005.
CENTERPOINT ENERGY RESOURCES CORP.
(Registrant)
By: /s/ DAVID M. MCCLANAHAN
-------------------------------------
David M. McClanahan
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on March 24, 2005.
SIGNATURE TITLE
- ------------------------ ----------------------------------------------------
/s/ DAVID M. MCCLANAHAN President, Chief Executive Officer and Director
----------------------- (Principal Executive Officer and Director)
(David M. McClanahan)
/s/ GARY L. WHITLOCK Executive Vice President and Chief Financial Officer
-------------------- (Principal Financial Officer)
(Gary L. Whitlock)
/s/ JAMES S. BRIAN Senior Vice President and Chief Accounting Officer
------------------ (Principal Accounting Officer)
(James S. Brian)
55
CENTERPOINT ENERGY RESOURCES CORP.
EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K
FOR FISCAL YEAR ENDED DECEMBER 31, 2004
INDEX OF EXHIBITS
Exhibits not incorporated by reference to a prior filing are designated by
a cross (+); all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.
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
56
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
57
There have not been filed as exhibits to this Form 10-K certain
long-term debt instruments, including indentures, under which the total amount
of securities do not exceed 10% of the total assets of CERC. CERC hereby agrees
to furnish a copy of any such instrument to the SEC upon request.
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
58