1UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.D. C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)15(D) OF THE SECURITIES AND
EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 1995FOR THE YEAR ENDED DECEMBER 31, 2002
[] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___
COMMISSION IRS EMPLOYER
FILE STATE OF IDENTIFICATION
NUMBER REGISTRANT INCORPORATION NUMBER
- ----------------------------------------------------------------------------------------------------------------------- -------------------------- ------------------- ---------------
1-7810 Energen Corporation AlabamaENERGEN CORPORATION ALABAMA 63-0757759
2-38960 Alabama Gas Corporation AlabamaALABAMA GAS CORPORATION ALABAMA 63-0022000
2101 Sixth Avenue North
Birmingham, Alabama 35203
(205) 605 RICHARD ARRINGTON JR. BOULEVARD NORTH
BIRMINGHAM, ALABAMA 35203-2707
TELEPHONE NUMBER 205/326-2700
HTTP://WWW.ENERGEN.COM
Securities Registered Pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS EXCHANGE ON WHICH REGISTERED
- ------------------- ----------------------------
Energen Corporation Common Stock, $0.01 par value New York Stock Exchange
Energen Corporation Preferred Stock Purchase Rights New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act: NONE
Indicate by a check mark whether registrants (1) have filed all reports required
to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrants
were required to file such reports) and (2) have been subject to such filing
requirements for the past 90 days. YES X NO --- ---____
Indicate by a check mark if disclosure of delinquent filesfilers pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) is not contained herein and
will not be contained, to the best of 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. ( )
Aggregate market value of the voting stock held by non-affiliates of the
registrants as of December 18, 1995:
Energen Corporation $271,868,000June 30, 2002:
Energen Corporation $931,042,350
Indicate number of shares outstanding of each of the registrant's classes of
common stock as of December 18, 1995:
Energen Corporation 10,984,566March 5, 2003:
Energen Corporation 34,868,363 shares
Alabama Gas Corporation 1,972,052 shares
Alabama Gas Corporation meets the conditions set forth in General Instruction
I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced
disclosure format pursuant to General Instruction I(2).
DOCUMENTS INCORPORATED BY REFERENCE
o
Energen Corporation Proxy Statement to be filed on or about December 21,
1995March 20,
2003 (Part III, Item 10-13)
o Portions
INDUSTRY GLOSSARY
FOR A MORE COMPLETE DEFINITION OF CERTAIN TERMS DEFINED BELOW, PLEASE REFER TO
RULE 4-10(A) OF REGULATION S-X, PROMULGATED PURSUANT TO THE SECURITIES ACT OF
1933 AND THE SECURITIES EXCHANGE ACT OF 1934, EACH AS AMENDED.
BASIS The difference between the futures price for a
commodity and the corresponding cash spot price. The
differential commonly is related to factors such as
product quality, location and contract pricing.
BASIN-SPECIFIC A type of Energen Corporation 1995 Annual Reportderivative contract whereby the contract's
settlement price is based on specific geographic
basin indices.
BEHIND PIPE RESERVES Oil or gas reserves located above or below the
currently producing zone(s) which cannot be
extracted until a recompletion or pay-add occurs.
CASH FLOW HEDGE The designation of a derivative instrument to Stockholdersreduce
the exposure to variability in cash flows from the
forecasted sale of oil, gas or natural gas liquids
production whereby the gains (losses) on the
derivative transaction are incorporatedanticipated to offset the
losses (gains) on the forecasted sale.
COLLAR A financial arrangement that effectively establishes
a price range for the commodity. The producer only
bears the risk of fluctuation between the minimum (or
floor) price and the maximum (or ceiling) price.
DEVELOPMENT WELL A well drilled within the proved area of an oil or
gas reservoir to the depth of a statigraphic horizon
known to be productive.
EXPLORATORY WELL A well drilled to a previously untested geologic
structure to determine the presence of oil or gas.
FUTURES CONTRACT An exchange-traded legal contract to buy or sell a
standard quantity and quality of a commodity at a
specified future date and price. Such contracts offer
liquidity and minimal credit risk exposure but lack
the flexibility of swap contracts.
HEDGING The use of derivative commodity instruments such as
futures, swaps and collars to help reduce financial
exposure to commodity price volatility.
LIQUIFIED NATURAL GAS Natural gas that is liquified by referencereducing the
(LNG) temperature to negative 260 degrees Fahrenheit. LNG
typically is used to supplement traditional natural
gas supplies during periods of peak demand.
LONG-LIVED RESERVES Reserves generally considered to have a productive
life of approximately 10 years or more, as measured
by the reserves-to-production ratio.
NATURAL GAS LIQUIDS (NGL) Liquid hydrocarbons that are extracted and separated
from the natural gas stream. NGL products include
ethane, propane, butane, natural gasoline and other
hydrocarbons.
ODORIZATION A characteristic odor added to natural gas so that
leaks can be readily detectable by smell.
OPERATIONAL ENHANCEMENT Any action undertaken to improve production
efficiency of oil and gas wells and/or reduce well
costs.
OPERATOR The company responsible for exploration, development
and production activities for a specific project.
PAY-ADD An operation within a currently producing wellbore
that attempts to access and complete an additional
pay zone(s) while maintaining production from the
existing completed zone(s).
PAY ZONE The formation from which oil and gas is produced.
PROVED DEVELOPED RESERVES The portion of proved reserves which can be expected
to be recovered through existing wells with existing
equipment and operating methods.
PROVED RESERVES Estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering
data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED The portion of proved reserves which can be expected
RESERVES (PUD) to be recovered from new wells on undrilled proved
acreage or from existing wells where a relatively
major expenditure is required for completion.
PUT OPTION A contract that gives the purchaser the right, but
not the obligation, to sell the underlying commodity
at a certain price on or before an agreed date.
RECOMPLETION An operation within an existing wellbore whereby a
completion in one pay zone is abandoned in order to
attempt a completion in a different pay zone.
RESERVES-TO- Ratio expressing years of supply determined by
PRODUCTION RATIO dividing the remaining recoverable reserves at year
end by actual annual production volumes.
SECONDARY RECOVERY The process of injecting water, gas, etc., into Part II, Items 5,a
formation in order to produce additional oil
otherwise unobtainable by initial recovery efforts.
SWAP A contractual arrangement in which two parties,
called counterparties, effectively agree to exchange
or "swap" variable and fixed rate payment streams
based on a specified commodity volume. The contracts
allow for flexible terms such as specific quantities,
settlement dates and location but also expose the
parties to counterparty credit risk.
TRANSPORTATION Moving gas through company pipelines on a contract
basis for others.
THROUGHPUT Total volumes of natural gas sold or transported by
the gas utility.
WORKING INTEREST The ownership interest in the oil and gas properties
which is burdened with the cost of development and
operation of the property.
WORKOVER A major remedial operation on a completed well to
restore, maintain, or improve the well's production
such as deepening the well or plugging back to
produce from a shallow formation.
e Following a unit of measure denotes that the oil and
natural gas liquids components have been converted to
cubic feet equivalents at a rate of 6 7, and 8 of this reportthousand cubic
feet per barrel.
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ENERGEN CORPORATION
19952002 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
PAGE
----
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Business..............................................................................3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Properties............................................................................9
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Proceedings.....................................................................9
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . 8Holders...................................9
PART II
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters . . . . . . . . . . 12Matters.................11
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Data..............................................................12
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Operations...........................................................................14
Item 7a. Quantitative and Qualitative Disclosures about Market Risk...........................28
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . 13Data..........................................29
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Disclosure.................................................................73
PART III
Item 10. Directors and Executive Officers of the Registrants . . . . . . . . . . . . . . . . . . 13Registrants..................................74
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Compensation...............................................................74
Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . 13Management.......................74
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . 13Transactions.......................................74
PART IV
Item 14. Controls and Procedures..............................................................75
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . . 148-K.....................75
Signatures .....................................................................................79
Certifications .....................................................................................81
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This Form 10-K is filed on behalf of Energen Corporation (Energen or the
Company) and Alabama Gas Corporation (Alagasco).
FORWARD-LOOKING STATEMENT AND RISK: Certain statements in this report express
expectations of future plans, objectives and performance of the Company and its
subsidiaries and constitute forward-looking statements made pursuant to the Safe
Harbor provision of the Private Securities Litigation Reform Act of 1995. Except
as otherwise disclosed, the Company's forward-looking statements do not reflect
the impact of possible or pending acquisitions, divestitures or restructurings.
The Company cannot guarantee the absence of errors in input data, calculations
and formulas used in its estimates, assumptions and forecasts. The Company
undertakes no obligation to correct or update any forward-looking statements
whether as a result of new information, future events or otherwise.
All statements based on future expectations rather than on historical facts are
forward-looking statements that are dependent on certain events, risks and
uncertainties that could cause actual results to differ materially from those
anticipated. Some of these include, but are not limited to, economic and
competitive conditions, inflation rates, legislative and regulatory changes,
financial market conditions, future business decisions, and other uncertainties,
all of which are difficult to predict.
There are numerous uncertainties inherent in estimating quantities of proved oil
and gas reserves and in projecting future rates of production and timing of
development expenditures. The total amount or timing of actual future production
may vary significantly from reserve and production estimates. In the event
Energen Resources Corporation is unable to fully invest its planned acquisition,
development and exploratory expenditures, future operating revenues, production,
and proved reserves could be negatively affected. The drilling of development
and exploratory wells can involve significant risks, including those related to
timing, success rates and cost overruns and these risks can be affected by lease
and rig availability, complex geology and other factors.
Although Energen Resources makes use of futures, swaps and fixed-price contracts
to mitigate risk, fluctuations in future oil and gas prices could materially
affect the Company's financial position and results of operation; furthermore,
such risk mitigation activities may cause the Company's financial position and
results of operations to be materially different from results that would have
been obtained had such risk mitigation activities not occurred. The
effectiveness of such risk-mitigation assumes that counterparties maintain
satisfactory credit quality.
PART I
ITEM 1. BUSINESS
GENERAL
Energen Corporation is a Birmingham-based diversified energy holding company
engaged primarily in natural
gas distribution and the acquisition, development, exploration and production of
oil, natural gas and oil.natural gas liquids in the continental United States and in
the purchase, distribution, and sale of natural gas, principally in central and
north Alabama. Its two major subsidiaries are Energen Resources Corporation and
Alabama Gas Corporation (Alagasco).
Energen was incorporated in Alabama in 1978 in connection with the
reorganization of its largestoldest subsidiary, Alagasco. Alagasco was formed in 1948
by the merger of Alabama Gas Company into Birmingham Gas Company, the
predecessors of which had been in existence since the late 1800's.mid-1800s. Alagasco became
a public company in 1953. Energen Resources was formed in 1971 as a subsidiary
of Alagasco and became a subsidiary of Energen in the 1978 reorganization.
On December 5, 2001, the Board of Directors of the Company approved a change in
the Company's fiscal year end from September 30 to December 31, effective
January 1, 2002. Alagasco retained a September 30 fiscal year end for rate
setting purposes.
The Company maintains a Web site with the address www.energen.com. The Company
does not include the information contained on its Web site as part of this
report nor is the information incorporated by reference into
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this report. The Company makes available free of charge through its Web site the
annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports
on Form 8-K, and any amendments to these reports. These reports are provided as
soon as reasonably practicable after such reports are electronically filed with
or furnished to the Securities and Exchange Commission.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The information required by this item is incorporated by reference fromprovided in Note 1520, Industry Segment
Information, in the Notes to the Consolidated Financial Statements of the 1995 Annual Report to
Stockholders, and is attached herein as Part IV, Item 14, Exhibit 13.Statements.
NARRATIVE DESCRIPTION OF BUSINESS
o- - OIL AND GAS OPERATIONS
GENERAL: Energen's oil and gas operations focus on increasing
production and adding proved reserves through the acquisition and
development of oil and gas properties. To a lesser extent, Energen
Resources explores for and develops new reservoirs, primarily in areas
in which it has an operating presence. Substantially all gas production
and all oil and natural gas liquids production is sold to third
parties. Energen Resources also provides operating services in the
Black Warrior Basin in Alabama for its partners and third parties.
These services include overall project management and day-to-day
decision-making relative to project operations.
At the end of 2002, Energen Resources' inventory of proved oil and gas
reserves totaled 1,262.9 billion cubic feet equivalent (Bcfe).
Substantially all of the company's approximately 1.3 trillion cubic
feet equivalent of reserves are located in the San Juan Basin in New
Mexico, the Black Warrior Basin in Alabama, the Permian Basin in west
Texas, and the north Louisiana/east Texas region. Approximately 82
percent of Energen Resources' year-end reserves are proved developed
reserves. Energen Resources reserves are long-lived, with a year-end
reserves-to-production ratio of 16. Natural gas represents
approximately 64 percent of Energen Resources' proved reserves, with
oil representing approximately 24 percent and natural gas liquids
comprising the balance.
GROWTH STRATEGY: Energen has operated for more than seven years under a
strategy to grow its oil and gas operations. Since the end of fiscal
year 1995, Energen Resources has invested approximately $715 million in
property acquisitions, $435 million in related development, and $90
million in exploration and associated development. Energen Resources'
capital investment for oil and gas activities over the five-year period
ending December 31, 2007, is currently expected to approximate $835
million.
Energen Resources' approach to the oil and gas business calls for the
company to pursue onshore North American property acquisitions which
offer proved undeveloped (PUD) and/or behind-pipe reserves as well as
operational enhancement potential. Energen Resources prefers operated
natural gas properties with long-lived reserves and multiple pay-zone
opportunities; however, Energen Resources does not preclude possible
acquisitions of properties that otherwise meet its investment
requirements.
Following an acquisition, Energen Resources focuses on increasing
production and reserves through development of the properties' PUD and
behind-pipe reserve potential as well as engaging in other development
activities. These activities include development well drilling,
behind-pipe recompletions, pay-adds, workovers, secondary recovery and
operational enhancements. Energen Resources prefers to operate its
properties in order to better control the nature and pace of
development activities.
Energen Resources' development activities can result in the addition of
new proved reserves and can serve to reclassify proved undeveloped
reserves to proved developed reserves. Proved reserve disclosures are
provided annually, although changes to reserve classifications occur
throughout the year. Accordingly, additions of new reserves from
development activities can occur throughout the year and may result
from numerous factors including, but not limited to, regulatory
approvals for drilling unit downspacing which increase the number of
available drilling locations; changes in the economic or operating
environments which allow previously uneconomic locations to be added;
technological advances which make reserve locations available for
4
development; successful development of existing PUD locations which
reclassify adjacent probable locations to PUD locations; increased
knowledge of field geology and engineering parameters relative to oil
and gas reservoirs; and changes in management's intent to develop
certain opportunities.
Since the end of fiscal year 1999, the Company's development efforts
have added approximately 298 Bcfe of proved reserves from the drilling
of approximately 540 gross development wells and 408 well recompletions
and pay-adds. In 2002, Energen Resources' successful development wells
and other activities added approximately 162 Bcfe of proved reserves.
The company drilled 232 gross development wells, performed some 95 well
recompletions and pay-adds, and conducted other operational
enhancements. Energen Resources' production from continuing operations
totaled 77.4 Bcfe in 2002 and is estimated to total 85 Bcfe in 2003,
including 82.4 Bcfe of estimated production from proved reserves owned
at December 31, 2002.
Most of Energen Resources' coalbed methane production generated
nonconventional fuels tax credits through December 31, 2002. In 2002,
Energen Resources' nonconventional fuels tax credits totaled $14.2
million. Nonconventional fuels tax credits are no longer generated due
to tax law changes effective December 31, 2002. To mitigate the effects
on corporate earnings in 2003, Energen Resources has replaced a portion
of the tax credit benefit with long-term, revenue-generating property
acquisitions and their related development activities and has increased
the number of available drilling locations through unit downspacing in
the Black Warrior Basin.
RISK MANAGEMENT: Energen Resources attempts to lower the risk
associated with its oil and natural gas business. A key component of
the company's efforts to manage risk is its acquisition versus
exploration orientation and its preference for long-lived reserves. In
pursuing an acquisition, Energen Resources primarily uses in its
evaluation models the then-current oil and gas futures prices, the
prevailing swap curve and, for the longer-term, its own pricing
assumptions. After a purchase, Energen Resources may use futures, swaps
and/or fixed-price contracts to hedge commodity prices on flowing
production for up to 36 months to help protect targeted returns from
price volatility. On an on-going basis, Energen Resources may hedge up
to 80 percent of its annual production in any given year depending on
its pricing outlook.
The Company adopted Statement of Financial Accounting Standards (SFAS)
No. 133 (subsequently amended by SFAS Nos. 137 and 138), "Accounting
for Derivative Instruments and Hedging Activities," on October 1, 2000.
This statement requires all derivatives to be recognized on the balance
sheet and measured at fair value. If a derivative is designated as a
cash flow hedge, the Company is required to measure the effectiveness
of the hedge, or the degree that the gain (loss) for the hedging
instrument offsets the loss (gain) on the hedged item, at each
reporting period. The effective portion of the gain or loss on the
derivative instrument is recognized in other comprehensive income as a
component of equity and subsequently reclassified into earnings when
the forecasted transaction affects earnings. The ineffective portion of
a derivative's change in fair value is required to be recognized in
earnings immediately. Derivatives that do not qualify for hedge
treatment under SFAS No. 133 must be recorded at fair value with gains
or losses recognized in earnings in the period of change.
The Company periodically enters into derivative transactions that do
not qualify for cash flow hedge accounting but are considered by
management to represent valid economic hedges and are accounted for as
mark-to-market transactions. These economic hedges may include, but are
not limited to, basis hedges without a corresponding New York
Mercantile Exchange (NYMEX) hedge, put options and hedges on
non-operated or other properties for which all of the necessary
information to qualify for cash flow hedge accounting is either not
readily available or subject to change.
See the Forward-Looking Statement and Risk in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of
Operations, for further discussion with respect to price and other
risk.
ENVIRONMENTAL MATTERS: Energen Resources is subject to various
environmental regulations. Management believes that Energen Resources
is in compliance with currently applicable standards of the
environmental agencies to which it is subject and that potential
environmental liabilities are minimal. Also, to the extent that
5
Energen Resources has operating agreements with various joint venture
partners, environmental costs would be shared proportionately.
OTHER: For a discussion of risks inherent in the Company's businesses,
see Item 7, Management's Discussion and Analysis of Financial Condition
and Results of Operations.
- - NATURAL GAS DISTRIBUTION
GENERAL: Alagasco Energen's principal subsidiary, is the largest natural gas distribution utility in
the state of Alabama. Alagasco purchases natural gas through interstate
and intrastate marketers and suppliers and distributes the purchased
gas through its distribution facilities for sale to residential,
commercial and industrial customers and other end-users of natural gas.
Alagasco also provides transportation services to industrial and
commercial customers located on its distribution system. These
transportation customers, acting
on their own or using Alagasco as their agent or acting on
their own, purchase gas directly from producers, marketers or other suppliers
and arrange for delivery of the gas into the Alagasco distribution
system. Alagasco then charges a fee to transport thissuch customer-owned gas
through its distribution system to the customer's
facility.customers' facilities.
Alagasco's service territory is located primarily in central and parts of north
Alabama and includes over 175approximately 188 cities and communities in 3028
counties. Birmingham, the
largest city in Alabama, and Montgomery, the state capital, are served by
Alagasco. The counties in which Alagasco provides service have an aggregate
area of more than 22,000 square miles and include the service territories of
various municipal gas distribution systems. The aggregate population of the counties served by Alagasco
is estimated to be 2.42.3 million. Among the cities served by Alagasco are
Birmingham, the center of the largest metropolitan area in Alabama, and
Montgomery, the state capital. During 19952002, Alagasco served an average
of 410,515425,630 residential customers 33,115 smalland 35,601 commercial, industrial and
industrial customers, and
48 large commercial and industrialtransportation customers. The Alagasco distribution system includes
approximately 8,6509,723 miles of main and more than 9,50011,395 miles of service
lines, odorization and regulation facilities, and customer meters.
Alagasco also operates two liquefied natural gas facilities which it uses to
meet peak demands.
APSC REGULATION: As a publican Alabama utility, in the state of Alabama, Alagasco is subject to
regulation by the Alabama Public Service Commission (APSC), which, has adopted several innovative approaches to rate regulation, including
Alagasco'sin
1983, established the Rate Stabilization and Equalization (RSE)
rate-setting process. ImplementedRSE was extended in 1983 and modified in 1985,2002, 1996, 1990, 1987 and
1990,1985. On June 10, 2002, the APSC extended RSE replacedfor a six-year period,
through January 1, 2008. Under the traditional utility rate case
3
5
with APSC-monitored periodic rate adjustments presently designed to give
Alagasco the opportunity to earn an averageAPSC order, Alagasco's allowed range
of return on average equity (ROE) at its
fiscal year-end within a specified range. Under Alagasco's current RSE
order, which became effective December 1990, Alagasco's allowed ROE range isremains 13.15 percent to 13.65 percent. Thepercent
throughout the term of the order, subject to change in the event that
the Commission, following a generic rate of return hearing, adjusts the
returns on equity of all major energy utilities operating under a
similar methodology. Alagasco is on a September 30 fiscal year for
rate-setting purposes (rate year).
Under RSE as extended, the APSC conducts quarterly reviews to
determine, based on Alagasco's budgetprojections and fiscal year-to-date
performance, whether Alagasco's projected ROE forreturn on average equity at the fiscalend of
the rate year will be within the allowed range. Reductions in rates can
be made quarterly to bring the projected ROEreturn within the allowed
range. Increases,range; increases, however, are permittedallowed only once each fiscalrate year,
effective on December 1, and cannot exceed 4 percent of prior-year
revenues. RSE limits Alagasco'sthe utility's equity upon which a return is
permitted to 60 percent of total capitalization and provides for
acertain cost control measuremeasures designed to monitor Alagasco's operations
and maintenance (O & M)&M) expense. If increasesUnder the inflation-based cost control
measurement established by the APSC, if the percentage change in O & M&M
expense per customer fallfalls within a range of 1.25 percentpoints above or below
the percentage change in the Consumer Price Index for allFor All Urban
CustomersConsumers (index range), no adjustment is required. If however, increasesthe change in
O & M&M expense per customer exceedexceeds the index range, three-fourthsthree-quarters of the
difference is returned to customers. To the extent increases in O & M expense per customer arethe change is less
than the index range, Alagasco will benefitthe utility benefits by one-half of the
difference through future rate adjustments.
Under its terms,The temperature adjustment rider to Alagasco's current RSE order continues until, after notice
to Alagasco,rate tariff, approved by
the APSC votesin 1990, was designed to either modifymitigate the earnings impact of
variances from normal temperatures. Alagasco performs this real-time
temperature adjustment calculation monthly, and the adjustments to
customers' bills are made in the same billing cycle in which the
weather variation occurs. Substantially all the customers to whom the
temperature adjustment applies are residential, small commercial and
small industrial. Alagasco's rate schedules for natural gas
distribution charges contain a Gas Supply Adjustment (GSA) rider that
permits the pass-through to customers of changes in the cost of gas
supply.
6
The APSC approved an Enhanced Stability Reserve (ESR) beginning October
1997, with an approved maximum funding level of $4 million, to which
Alagasco may charge the full amount of: (1) extraordinary O&M expenses
resulting from force majeure events such as storms, severe weather, and
outages, when one or discontinue its operation.
On October 4, 1993,a combination of two such events results in more
than $200,000 of additional O&M expense during a rate year; or (2)
individual industrial and commercial customer revenue losses that
exceed $250,000 during the rate year, if such losses cause Alagasco's
return on equity to fall below 13.15 percent. Following a year in which
a charge against the ESR is made, the APSC unanimously votedprovides for accretions to
extend RSE until such time
as certain hearings mandated by the Energy Policy ActESR in an amount of 1992 (Energy Act)
in connection with integrated resource planning and demand side management
programs are completed. The Energy Act proceedings are expected to conclude
during fiscal 1996 at which time the Commission is expected to begin a
review of Alagasco's RSE. No time table for review has yet been
established.
FERC REGULATION: Alagasco's interstate pipeline suppliers, Southern
Natural Gas Company (Southern) and Transcontinental Gas Pipeline Corporation
(Transco), are subject to regulation by the Federal Energy Regulatory
Commission (FERC). Among other things, FERC regulates the character of
services that Southern and Transco can offer and the rates and fees they can
charge Alagasco and other customers for gas transportation services; thus,
FERC can directly affect Alagasco's services and operating expenses.
On March 15, 1995, Southern filed a comprehensive settlement with the FERC
in the form of a Stipulation and Agreement (the Settlement) to resolve all
issues in Southern's six pending rate cases, as well as to resolve all Gas
Supply Realignment (GSR) and transition cost issues resulting from the
implementation of FERC Order 636. The Settlement is supported by parties
representingno more than 90 percent of$40,000 monthly until the firm transportation demand on
Southern's system, including local distribution companies (including
Alagasco), municipal distribution systems, major gas producers, large
industrial end users, marketers, and state commissions (including the APSC).
On September 29, 1995, the FERC issued its Order Accepting Settlement,
Severing Contesting parties, and Issuing Certificates and Approving
Abandonment (Settlement Order). The Settlement Order approves the Settlement
with minor modifications. Contesting parties had 30 days from the date of
the Settlement Order to file motions for rehearing and several such motions
were timely filed. Until such motions are ruled on by the FERC, the
Settlement Ordermaximum
funding level is not considered to be final.
Specifically, the Settlement provides for the following: (1) the resolution
of all cost of service and rate design issues in Southern's six pending rate
cases and the establishment of reduced rates for the purpose of calculating
rate case refunds; (2) the implementation of reduced settlement rates on an
interim basis for supporting parties commencing March 1, 1995 (by order
dated April 4, 1995, FERC approved these interim rates pending its final
review of the merits of the Settlement); (3) the resolution of all GSR and
other transition cost issues resulting from FERC Order 636; (4) lower GSR
cost recovery through the reduction and earlier payout of GSR costs; (5) a
three-year moratorium on general rate increases; and (6) the resolution and
disposition of all rate case and GSR refunds for supporting parties. With
respect to this
4
6
last point, the Settlement provides that all rate case refunds will be used
to offset a portion of Southern's remaining GSR liability. In addition, as a
result of the recalculated GSR surcharges for the period January 1, 1994, to
February 28, 1995, Southern will refund over-collected GSR costs. Neither
the total amount of this refund nor Alagasco's share has yet been
determined; therefore, no amounts have been recorded in the financial
statements. In the Settlement filing with FERC, Southern has represented
that the Settlement will allow Southern and the supporting parties to
resolve all issues relating to GSR and other transition costs, the majority
of which costs will be collected by the end of calendar 1995. Alagasco
estimates that it has a remaining GSR liability of approximately $2.4
million to be paid through December 1995 and approximately $2.6 million in
other transition costs to be paid through June 1998 and has recorded
such amounts in the financial statements. Because these costs will be
recovered in full from Alagasco's customers in a timely manner through the
GSA rider of Alagasco's Tariff, the Company has recorded a corresponding
regulatory asset in the accompanying financial statements.achieved.
GAS SUPPLY: The AlagascoAlagasco's distribution system is connected to and has firm
transportation contracts with two major interstate pipeline systems--Southernsystems -
Southern Natural Gas Company (Southern) and Transco. Effective November 1, 1993, Alagasco's
pre-Order 636 contract demand and firm transportation with Southern
converted to 250,924 Mcf (thousandTranscontinental Gas Pipe
Line Corporation (Transco). On Southern's system, Alagasco has 251,679
thousand cubic feet) per dayfeet (Mcfd) of No-Notice Firm Transportation service
for a period of 15 years, 91,946 Mcf per daythrough October 31, 2008, and 134,332 Mcfd of Firm TransportationTransporation
service, for 15 years,of which 40,000 Mcfd expires April 30, 2005, 1,959 Mcfd
expires October 31, 2005 and 50,000 Mcf per day of Firm
Transportation for five years. Southern also unbundled its existing storage
capacity. Alagasco's pro rata share of this storage is 12,426,687 Mcf.
Alagasco has a maximum withdrawal rate from storage of 250,924 Mcf per day
and a maximum injection rate into storage of 95,590 Mcf per day.the balance expires October 31, 2008. The
Transco firm transportationFirm Transportation contract, which expires in 2001,October 31, 2005,
provides for maximum
daily firm transportation of up to 100,000 Mcf. Thus the CompanyMcfd. As a result, Alagasco has a peak day
firm interstate pipeline transportation capacity of 492,870 Mcf per day.486,011 Mcfd.
Alagasco has replaced the sales service formerly provided by Southern12,464,074 Mcf of storage capacity on Southern's system,
with a maximum withdrawal rate of 251,679 Mcfd from storage and a
maximum injection rate of 95,878 Mcfd to storage. Alagasco also
operates two liquified natural gas (LNG) facilities used to meet peak
demand.
Alagasco purchases gas from various gas producers and marketers,
including affiliates of Southern, and Transco and from certain intrastate producers
including Basin
Pipeline Corp., an Energen subsidiary.and marketers. Alagasco has contracts in place to purchase up to
a total of 286,776 Mcf per day233,230 Mcfd of firm supply, of which 241,946234,332 Mcfd is supported by firm
transportation on the Transco and Southern systems 14,830 Mcf provides redundant supply on the Southern system, and 30,000 Mcfapproximately
21,450 Mcfd is purchased at the city gate fromunder intrastate suppliers. This
volume,firm supply
contracts. These firm supply volumes along with Alagasco's maximum
withdrawal from storage of 250,924 Mcf
per day251,679 Mcfd and LNG peak-shaving capacity
of 200,000 Mcf per day of liquefied natural gas peak shaving
capacity, givesMcfd, give Alagasco a peak day firm supply of 722,870 Mcf per day.684,909 Mcfd.
Alagasco also utilizes the Southern and Transco pipeline systems to access spot
market gas in order to supplement its firm system supply and serve its
industrial and large commercial transportation customers. Deliveries of
sales and transportation gas totaled 97,840 million cubic feet in 2002.
COMPETITION AND PRICING:RATE FLEXIBILITY: The price of natural gas is a
significant marketingcompetitive factor in theAlagasco's service territory,
served by Alagasco; propane,particularly among large commercial and industrial transportation
customers. Propane, coal and fuel oil are readily available, and many
major industrial customers have the capability to switch to alternate fuels.fuels
and/or alternate sources of gas. In the residential and small
industrialcommercial and commercialindustrial markets, electricity is the principal
competitor. NaturalWith the support of the APSC, Alagasco has implemented a
variety of flexible rate strategies to help it compete for the large
customers' gas service availableload in the deregulated marketplace. Rate flexibility
remains critical as the utility faces competition for the large
customer load. To date, the utility has been effective in utilizing its
flexible rate strategies to minimize bypass and price-based switching
to alternate fuels and alternate sources of gas.
In 1994 Alagasco implemented the P Rate in response to the competitive
challenge of interstate pipeline capacity release. Under this tariff
provision, Alagasco releases much of its excess pipeline capacity and
repurchases it as agent for its transportation customers generally falls into two
categories -- interruptible and firm. Interruptible service is
contractually subjectunder 12 month
contracts. The transportation customers benefit from lower pipeline
costs. Alagasco's core market customers benefit, as well, since the
utility uses the revenues received from the P Rate to interruption by Alagascodecrease gas
costs for various reasons, the
most common of which is curtailment of industrial customers during periods
of peak residential heating demand on the Alagasco system. Firm service is
generally not subject to interruption and, therefore, is more expensive than
interruptible service. Firm service is generally provided toits residential and small commercial and industrial
customers. Interruptible service is
generally provided to large commercialIn 2002, approximately 300 of Alagasco's transportation
customers utilized the P Rate, and industrial customers which
typically have the capacity to reduce consumption by adjusting their
production schedules or by switching to alternate fuels during periods of
interruption. Deliveries of sales and transportation gas totaled 101,447
MMcf (million cubic feet)resulting reduction in 1995.
In 1994, capitalizing on federally mandated changes in the natural gas
industry, Alagasco implemented the "P" Rate. This tariff allows the utility
to, in effect, release available pipeline capacity thereby reducing
5
7
pipeline transportation costs for its 250 transportation customers. The
lower costs help prevent bypass. Also, because revenue received from
capacity release reduces core
market gas costs Alagasco's competitive
position in the residential and small commercial markets is enhanced as
well.
Alagasco has atotaled approximately $9.1 million.
The Competitive Fuel Clause (CFC) as part ofand Transportation Tariff also have
been important to Alagasco's ability to compete effectively for
customer load in its rate tariff
whichservice territory. The CFC allows Alagasco to
adjust large commercial and industrial pricescustomer rates on a case-by-case basis to compete with
either alternate fuels orand alternate sources of gas. The GSA rider to
Alagasco's tariff increasesallows the rates paid
by other customersCompany to recover the reduction in
ratescharges allowed under the CFC because the retention of any customer,
particularly large commercial and industrial transportation customers,
benefits all customers by recovering a portion of the system's fixed
cost. Alagasco also has acosts. The Transportation Tariff (the Tariff) which
allows the CompanyAlagasco to
7
transport gas for customers, rather than buyingbuy and reselling gasresell it to them. The Tariffthem, and
is based on Alagasco's gas sales profit margin so that operating margins
are unaffected. During 2002 substantially all of Alagasco's net income is not affected whether it transports
or sells gas. The Tariff also may be adjusted under the CFC. Of Alagasco's
total large
commercial and industrial customer deliveries during 1995, 99.5
percent (46,207 MMcf) was fromwere the transportation
of customer-owned gas. In addition, Alagasco served as gas purchasing
agent for approximately 99 percent of its transportation customers.
Alagasco also uses long-term special contracts as a vehicle for
retaining large customer load. At the end of 2002, 49 of the utility's
largest commercial and industrial transportation customers were under
special contracts of varying lengths.
Natural gas service available to Alagasco customers falls into two
broad categories: interruptible and firm. Interruptible service
contractually is subject to interruption by Alagasco for various
reasons; the most common occurrence is curtailment of industrial
customers during periods of peak core market heating demand.
Interruptible service typically is provided to large commercial and
industrial transportation customers who can reduce their gas
consumption by adjusting production schedules or by switching to
alternate fuels for the duration of the service interruption. More
expensive firm service, on the other hand, generally is not subject to
interruption and is provided to residential and small commercial and
industrial customers; these core market customers depend on natural gas
primarily for space heating.
GROWTH: Customer growth presents a major challenge for Alagasco, has supplemented traditionalgiven
its mature, slow-growth service area. In 2002, Alagasco's average
number of customers declined slightly due to the previous year's high
gas costs and industrial load loss resulting from an economic slowdown.
The utility penetrated 86 percent of the new single-family housing
market in its service area and 18 percent of the new multi-family
housing market. For 2003, Alagasco will concentrate on maintaining its
current penetration levels in the residential new construction market
while increasing its focus on generating additional revenue in the
small and large commercial and industrial market segments.
A vehicle for supplementing Alagasco's normal growth with
acquisitions of municipally-owned gas distribution systems.continues to be
Alagasco's municipal acquisition program. Since 1985, Alagasco has
acquired 20 such23 municipally owned systems including the 500-customer gas system
of Ragland purchased in early fiscal 1996. Moreadding more than 42,00043,000 customers have
been added
through initial system purchases and subsequent customer additions, as Alagasco has increased the relatively low saturation rates in
the acquired areas through a variety of marketing efforts including offering
natural gas service to propane customers already situated on the municipal
system lines, extending the acquired municipal system into nearby
neighborhoods that desire natural gas service, and marketing natural gas
appliances to existing and new customers.additions.
Approximately 8075 municipal systems representing about 250,000 customers, remain in Alabama,Alabama. Alagasco
continues to pursue the purchase of municipal gas systems, and many
are located in or near Alagasco's existing service territory. The Company is
optimisticcompany
management believes that additional acquisition opportunities will arise in the
future.
WEATHER:such acquisitions could offer future growth
opportunities.
SEASONALITY: Alagasco's gas distribution business is highly seasonal
since a material portion of Alagasco'sthe utility's total sales and delivery
volumes is to customers whose use varies depending upon temperature, principally
residential, small commercial and small industrialspace heating customers. Alagasco's rate tariff includes
a temperature adjustment rider primarily for residential, small
commercial and small industrial customers which is designed to
mitigatesubstantially mitigates
the effect of departures from normal temperature on Alagasco's
earnings. The calculation is performed monthly, and adjustments are
made to customers' bills in the actual month the weather variation
occurs.
ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight
former manufactured gas plant sites of which it still owns four, and five manufactured gas
distribution sites, of which itsites. It still owns one. A
preliminaryfour of the plant sites and one of
the distribution sites. An investigation of the sites does not indicate
the present need for remediation activities. Management expects that,
should remediation of any such sites be required in the future,
Alagasco's share ifof any of suchassociated costs will not materially affect the
Company's results of its operations or financial condition of Alagasco.
o OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Energen's oil and gas exploration and production activities are conducted by
its subsidiary, Taurus Exploration, Inc. (Taurus), and involve the
exploration for and the production of natural gas and oil from conventional
and nonconventional reservoirs. Taurus's 1995 oil and gas production
totaled 10.1 Bcf (with oil expressed in natural gas equivalents), and the
average sales price was $1.83 per Mcf equivalent. Conventional oil and gas
reserves of 70,179 MMcf equivalents plus nonconventional gas reserves of
25,004 MMcf combine for total oil and gas reserves at fiscal year-end of
95,183 MMcf equivalents.
CONVENTIONAL: Taurus's conventional oil and gas strategy is to aggressively
grow its reserve base primarily by making significant acquisitions of oil
and gas properties through its joint acquisition agreements with Sonat
Exploration Company, PMC Reserve Acquisition Company, and United Meridian
6
8
Corporation (UMC), formerly General Atlantic Resources, Inc., along with its
internal and independent evaluation of other property acquisition
opportunities. A more thoroughcondition.
OTHER: For a discussion of Taurus's acquisition strategy
is includedrisks inherent in the 1995 Annual Report to Stockholders, pages 32Company's businesses,
see Management's Discussion and 33.
Taurus will continue to supplement its returns with exploratory drilling.
Taurus utilizes several avenues to help ensure a continuing flowAnalysis of high
quality exploratory prospects including its participationFinancial Condition and
Results of Operations as set forth in UMC's offshore
exploratory program, a multi-year 3-D seismic joint venture with King Ranch
and Holley Petroleum, Inc. covering 200 offshore Texas blocks, and other
offshore lease sales with various industry partners.
Taurus's exploration activities are concentrated in the shallow watersItem 7 of the Gulf of Mexico. Eight successful discoveries during 1995 added reserves
of 10 Bcf equivalents. Proved property acquisitions added reserves of 26.7
Bcf equivalents.
NONCONVENTIONAL: Taurus's nonconventional gas strategy is to focus on
operating the large projects in which it has a small working interest and
operating for others; supplementing these activities, Taurus also consults
on a limited basis. Taurus does not anticipate additional major project
development in the Black Warrior Basin. Taurus does plan, however, to
continue its operating activities.
As a result of its 1994 evaluation of North American coalbed methane
investment opportunities which indicated that available opportunities did
not meet Taurus's current risk profile, Taurus reduced and reorganized its
coalbed methane staff during 1995 to match its ongoing operational needs. No
additional restructuring is anticipated at this time.
At September 30, 1995, Taurus had working interests in 418 coalbed methane
wells and royalty interests in an additional 216 wells, all located in
Alabama's Black Warrior Basin. Gas produced from these wells through the
year 2002 qualifies for the Section 29 tax credit for producing fuel from
nonconventional sources.
Taurus is the operator of more than 950 coalbed methane wells, including
wells in an existing project owned by TECO Coalbed Methane, Inc., one of
Taurus's coalbed methane joint venture partners in other projects. Under
the terms of the agreement, Taurus provides technical, administrative and
operating services for a fee and receives additional compensation based on
the project's profitability.
During 1994, Taurus signed a multi-year strategic alliance with Conoco, Inc.
designed to enhance both companies' coalbed methane programs. During 1995,
Taurus provided consulting and associated services relative to the
acquisition, exploration and development of coalbed methane properties to
complement Conoco's capabilities and the companies mutually agreed to
terminate the alliance late in the fiscal year. Also during 1995, Taurus
decided that it would not pursue international coalbed methane investment
opportunities since such opportunities did not meet Taurus's risk parameters.
Most of the gas produced from the coalbed methane wells in which Taurus has
an interest is being sold under long-term contracts which provide markets
for 100 percent of the wells' production capacity and is sold at prices
indexed to the monthly Gulf Coast spot market.
ENVIRONMENTAL MATTERS: Taurus is subject to various environmental
regulations. Management believes that Taurus is in compliance with
currently applicable standards of the environmental agencies to which it is
subject and that potential environmental liabilities, if any, are minimal.
Also, to the extent Taurus has operating agreements with various joint
venture partners, environmental costs, if any, would be shared
proportionately.
7
9
o INTRASTATE GAS GATHERING AND TRANSMISSION
Energen operates an intrastate gas pipeline and gathering system through its
subsidiary, Basin Pipeline Corp. (Basin). Basin's pipeline and gathering
facilities primarily serve certain Taurus coalbed methane properties.
o COMBUSTION TECHNOLOGY
Prior to May 1994, through its American Heat Tech, Inc. (Heat Tech)
subsidiary, Energen owned a 41 percent equity interest in American
Combustion, Inc. During May 1994, a substantial portionPart II of this interest
was sold leaving Heat Tech with approximately an 8 percent ownership
interest. ACI designs, manufactures and markets high temperature combustion
technology products.
o PROPANE SALES
Prior to the June 1994 sale of substantially all of the assets of W & J
Propane Gas, Inc., Energen had been involved in the retail propane
distribution business.Form
10-K.
EMPLOYEES
The Company has 1,4311,533 employees; Alagasco employs 1,288; Taurus1,259; Energen Resources
employs 130;261; and Energen's other subsidiaries employ 13. The Company believes
that its relations with employees are good.
8
ITEM 2. PROPERTIES
The corporate headquarters of Energen, Alagasco and TaurusEnergen Resources are
located in leased office space in Birmingham, Alabama. Energen Resources
maintains leased offices in Houston and Midland, Texas, in Farmington, New
Mexico, in Oak Grove and Vance, Alabama and in Arcadia, Louisiana. For a
description of Energen Resources' oil and gas properties, see the discussion
under Item 1-Business. Information concerning Energen Resources' production,
reserves and development is summarized in the table below and included in Note
19, Oil and Gas Operations (unaudited), in the Notes to Financial Statements
which is included in this Form 10-K.
YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2002
----------------- -----------------
Production Volumes Reserves
(MMcfe) (MMcfe)
----------------- -----------------
San Juan Basin 27,133 548,744
Permian Basin 23,878 357,455
Black Warrior Basin 13,494 257,662
North Louisiana/East Texas 11,376 82,086
Other 2,092 16,981
------ ---------
Total 77,973 1,262,928
====== =========
The properties of Alagasco consist primarily of its gas distribution system,
which includes more than 8,6509,723 miles of main, more than 9,50011,395 miles of service
lines, odorization and regulation facilities, and customer meters. Alagasco also
has two liquefied natural gasLNG facilities, 23 commercialseven division offices, four payment centers, five
district offices, nine service centers, and other related property and
equipment, some of which are leased by Alagasco. For a further description of
Taurus's oil and gasAlagasco's properties, see the discussion under Item 1--Business. Information concerning Taurus's production, reserves and
development is included in Note 14 to the Consolidated Financial Statements
which is incorporated by reference from the 1995 Annual Report to Stockholders
and is included in Part IV, Item 14, Exhibit 13, herein. The proved reserve
estimates are consistent with comparable reserve estimates filed by Taurus with
any federal authority or agency.1-Business.
ITEM 3. LEGAL PROCEEDINGS
ThereEnergen and its affiliates are, nofrom time to time, parties to various pending or
threatened legal proceedings. Certain of these lawsuits include claims for
punitive damages in addition to other specific relief. Based upon information
presently available and in light of available legal and other defenses,
contingent liabilities arising from threatened and pending litigation are not
considered material legal proceedings pending, other than routine litigation
incidentalin relation to the Company'srespective financial positions of Energen
and its affiliates. It should be noted, however, that Energen and its affiliates
conduct business in Alabama and other jurisdictions in which the Companymagnitude and
frequency of punitive damage awards may bear little or any of its
subsidiaries is a party. There are no material legal proceedingsrelation to
which any
officerculpability or director of the Company or any of its subsidiaries is a party or has
a material interest adverseactual damages thus making it difficult to the Company.predict litigation
results.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth
quarter of 1995.
82002.
9
10
EXECUTIVE OFFICERS OF THE REGISTRANTS
ENERGEN CORPORATION
Name Age Position (1)
- ---- --- ------------
Rex J. Lysinger 58Wm. Michael Warren, Jr. 55 Chairman of the Board
President and Chief Executive Officer (2)
Wm. Michael Warren, Jr. 48 President and Chief Operating Officer (3)
Geoffrey C. Ketcham 4452 Executive Vice President, Chief Financial Officer
and Treasurer (3)
James T. McManus 44 President and Chief Operating Officer of Energen
Resources (4)
Dudley C. Reynolds 42 General Counsel and Secretary (5)
Gary C. Youngblood 52 Executive Vice50 President and Chief Operating Officer of Alagasco
(6)
James T. McManus 37 Executive(5)
Grace B. Carr 47 Vice President and Chief Operating Officer of
Taurus (7)
John A. Wallace 51 Senior Vice President--Methane of Taurus (8)Controller (6)
J. David Woodruff, Jr. 39 Vice President--Legal46 General Counsel and Assistant Secretary and Vice
President, CorporatePresident-Corporate Development (9)(7)
NOTES: (1) All executive officers of Energen have been employed by
Energen or a subsidiary for the past five years. Officers
serve at the pleasure of itsthe Board of Directors.
(2) Served as Vice President of Alagasco from July 1975 toMr. Warren has been employed by the Company in various
capacities since 1983. In January 1977, when1992 he was elected
President. Elected President and Chief Operating Officer of Energen uponand all of
its formationsubsidiaries, in 1978. ElectedOctober 1995 he was elected Chief
Executive Officer of Alagasco and Energen Resources, in
February 1997 he was elected Chief Executive Officer of
Energen and effective January 1, 1998, he was elected Chairman
of the Board of Energen and each of its subsidiaries September 1982. Currently Chairman of
the Board of Energen and all subsidiaries and Chief Executive
Officer of Energen. Servessubsidiaries. Mr.
Warren serves as a Director of Energen and each of its
subsidiaries. (3) Served as Senior Vice President and General Counsel of Alagasco
from September 1983 to October 1984, when he was elected President
and Chief Operating Officer of that corporation. Elected Executive
Vice President of Energen June 1987 and elected President and Chief
Operating Officer of Energen April 1991. Elected President and
Chief Operating Officer of all Energen subsidiaries (except W & J)
January 1992. Elected Chief Executive Officer of Alagasco and
Taurus effective October 1995. Serves asHe is also a Director of EnergenProtective Life
Corporation.
(3) Mr. Ketcham has been employed by the Company in various
financial and each of its subsidiaries.
(4) Elected Controller of Alagasco November 1981, Vice President and
Controller June 1984, Vice President--Finance and Planning of
Alagasco June 1985 and Vice President--Planning of Energen August
1986. Elected Vice President--Finance, Chief Financial Officer and
Treasurer of Energen and each of its subsidiaries June 1987.
Elected Senior Vice President--Finance, Chief Financial Officer and
Treasurer of Energen and each of its subsidiaries April 1989.
Electedstrategic planning capacities since 1981. He has
served as Executive Vice President, Chief Financial Officer
and Treasurer of Energen and each of its subsidiaries since
April 1991.
9
11
(5) Served as Staff Attorney for Energen(4) Mr. McManus has been employed by the Company in various
capacities since 1986. He was elected Executive Vice President
and its subsidiaries to
November 1984, when he was named Senior Attorney. Elected
Assistant Secretary in 1985 and Secretary effective September 1986.
Elected Vice President--Legal and SecretaryChief Operating Officer of Energen Resources in October
1995 and eachPresident of its subsidiaries June 1987. ElectedEnergen Resources in April 1997.
(5) Mr. Reynolds has been employed by the Company in various
capacities since 1980. He was elected as General Counsel and
Secretary of Energen and each of its subsidiaries in April
1991. (6) Served as District Manager--Birmingham District until June 1985,
when heHe was elected Vice President--Birmingham Operations; Elected
Senior Vice President-Administration of Alagasco April 1991.
Elected Executive Vice President of Alagasco October 1993. Electedand Chief Operating Officer of
Alagasco effective October 1995.
(7) Served as Director of Corporate Accounting of Energen until
November 1988, when heJanuary 1, 2003.
(6) Ms. Carr was employed by the Company in various capacities
from January 1985 to April 1989. She was not employed from May
1989 through December 1997. She was elected Controller of
Energen; Elected
Controller of Alagasco May 1989. Elected Assistant Vice
President--Corporate Development of Energen June 1990. Elected
Vice President--Financein January 1998 and Corporate Development of Energen and
Vice President--Finance and Planning of Alagasco effective April
1991. Elected Executiveelected Vice President and
Chief Operating OfficerController of Taurus effectiveEnergen in October 1995.
(8) Served as Manager, Methane Development of Taurus until August 1988,
when he2001.
(7) Mr. Woodruff has been employed by the Company in various
capacities since 1986. He was elected as Vice President Methane Operations of Taurus.
Elected Vice President Methane Exploration and Production of Taurus
November 1990. Elected Senior Vice President--Methane of Taurus
February 1992.
(9) Served as Staff Attorney for Alagasco from March 1986 to June 1987
when he was named Senior Attorney. Elected Assistant Vice
President--LegalPresident-Legal
and Assistant Secretary of Energen and each of its
subsidiaries November 1988. Electedin April 1991 and Vice President--LegalPresident-Corporate
Development of Energen in October 1995. He was elected General
Counsel and
Assistant Secretary of Energen and each of its subsidiaries
April
1991. Elected Vice President--Legal, and Assistant Secretary and
Vice President--Corporate Development of Energen and each of its
subsidiaries October 1995.effective January 1, 2003.
10
12
ALABAMA GAS CORPORATION
Name Age Position (1)
---- --- ------------
Rex J. Lysinger 58 Chairman of the Board (2)
Wm. Michael Warren, Jr. 48 President and Chief Executive Officer (2)
Geoffrey C. Ketcham 44 Executive Vice President and Chief Financial Officer (2)
Dudley C. Reynolds 42 General Counsel and Secretary (2)
Gary C. Youngblood 52 Executive Vice President and Chief Operating Officer (2)
Roy F. Etheredge 59 Senior Vice President (3)
George M. Taylor 59 Vice President--State Operations (4)
Gerald G. Turner 61 Vice President--Rates (5)
Donald C. Wiseman 57 Senior Vice President--Gas Supply (6)
J. David Woodruff, Jr. 39 Vice President--Legal and Assistant Secretary (2)
Paula H. Rushing 42 Controller (7)
NOTES: (1) All executive officers of Alagasco have been employed by
Energen or a subsidiary for the past five years. Officers
serve at the pleasure of the Board of Directors.
(2) See discussion of Energen officers on prior pages.
(3) Elected Assistant Vice President in 1983, Vice
President--Northern Division in 1984. Elected Vice
President--State Operations in May 1985. Elected Senior Vice
President--Operations April 1991.
(4) Elected Assistant Vice President--Birmingham Operations in
1988. Elected Vice President-- Birmingham Operations in 1991.
Elected Vice President--Technical Services in 1993. Elected
Vice President--State Operations in May 1995.
(5) Served as Director of Rates and Regulations until he was
elected Assistant Vice President--Rates in June 1987. Elected
Vice President--Rates May 1989.
(6) Elected Assistant Vice President--Gas Supply in 1988. Elected
Vice President--Gas Supply in 1990. Elected Senior Vice
President--Gas Supply in October 1995.
(7) Served as Director of General Accounting of Alagasco until
October 1995 when she was elected Controller.
11
13
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
The information regardingQUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE
Quarter ended (in dollars) HIGH LOW CLOSE DIVIDENDS PAID
- -------------------------- ---- --- ----- --------------
December 31, 1999 21.25 15.75 18.06 .165
March 31, 2000 18.94 14.69 15.94 .165
June 30, 2000 23.69 16.00 21.81 .165
September 30, 2000 30.38 21.00 29.75 .170
------- ------ ------ -----
December 31, 2000 33.56 26.06 32.19 .170
March 31, 2001 35.30 27.50 35.30 .170
June 30, 2001 40.25 26.75 27.60 .170
September 30, 2001 28.21 21.50 22.50 .175
------- ------ ------ -----
December 31, 2001 25.20 21.50 24.65 .175
------- ------ ------ -----
March 31, 2002 26.49 21.69 26.45 .175
June 30, 2002 29.25 24.70 27.50 .175
September 30, 2002 27.53 21.65 25.31 .180
December 31, 2002 29.99 22.50 29.10 .180
------- ------ ------ -----
Energen's common stock andis listed on the frequency and amount
of dividends paid duringNew York Stock Exchange under the past two years with respect to such stock is
incorporated by reference from the 1995 Annual Report to Stockholders, page 34,
and is included in Part IV, Itemsymbol
EGN. On February 14, Exhibit 13, herein. At October 29, 1995,2003, there were approximately 6,0007,930 holders of record of
Energen's common stock. For
restrictions on Energen's present and future ability to pay dividends, see Note
3 to the Consolidated Financial Statements which is incorporated by reference
from the 1995 Annual Report to Stockholders and is included in Part IV, Item
14, Exhibit 13, herein. At the date of this filing, Energen Corporation owns all
the issued and outstanding common stock of Alabama Gas Corporation.
The following table summarizes information concerning securities authorized for
issuance under equity compensation plans:
Number of Securities Remaining
Number of Securities to Weighted Available for Future Issuance
be Issued Upon Exercise Average Under Equity Compensation Plans
Plan Category of Outstanding Options Exercise Price
------------- ---------------------- -------------- -------------------------------
Equity compensation plans
approved by security holders 621,007 $20.38 2,326,897
Equity compensation plans not
approved by security holders -- -- --
------- ------ ---------
Total 621,007 $20.38 2,326,897
======= ====== =========
11
ITEM 6. SELECTED FINANCIAL DATA
Energen Corporation
The information regarding selected financial data is incorporated by reference
fromas set forth below should be read in conjunction
with the 1995 Annual ReportConsolidated Financial Statements and the Notes to Stockholders, pages 56-57, and isFinancial Statements
included in Part IV, Item 14, Exhibit 13, herein.
Alabama Gas Corporation
(unaudited)this Form 10-K.
SELECTED FINANCIAL AND COMMON STOCK DATA
ENERGEN CORPORATION
====================================================================================================
YEARSThree Months
YEAR ENDED SEPTEMBEREnded Year Ended Year Ended Year Ended Year Ended Year Ended
(dollars in thousands, DECEMBER 31, December 31, September 30, 1995 1994 1993 1992 1991
(IN THOUSANDS)
====================================================================================================September 30, September 30, September 30, September 30,
except per share amounts) 2002 2001* 2001 2000 1999 1998 1997
------------ ------------- ------------ ------------- ------------- ------------- -------------
INCOME STATEMENT
Operating revenues $295,967 $344,637 $330,560 $310,726 $309,128$ 677,175 $ 146,164 $ 777,374 $ 551,409 $ 492,942 $498,398 $446,684
Income from continuing
operations before
cumulative effect of
change in accounting
principle $ 70,586 $ 3,579 $ 66,087 $ 52,535 $ 41,453 $ 35,828 $ 28,736
Net income $ 15,72168,639 $ 14,8963,658 $ 13,02467,896 $ 12,42053,018 $ 11,97041,410 $ 36,249 $ 28,997
Diluted earnings
per average
common share from
continuing operations
before cumulative
effect of change in
accounting principle $ 2.09 $ 0.12 $2.13 $ 1.73 $ 1.38 $ 1.22 $ 1.13
Diluted earnings
per average
common share $ 2.03 $ 0.12 $2.18 $ 1.75 $ 1.38 $ 1.23 $ 1.14
---------- ----------- ---------- ---------- ---------- -------- --------
BALANCE SHEET
Capitalization at
year-end:
Common shareholders'
equity $ 582,810 $ 474,205 $ 480,767 $ 400,860 $ 361,504 $329,249 $301,143
Long-term debt 512,954 544,133 544,110 353,932 371,824 372,782 279,602
---------- ----------- ---------- ---------- ---------- -------- --------
Total capitalization $1,095,764 $1,018,338 $1,024,877 $ 754,792 $ 733,328 $702,031 $580,745
---------- ----------- ---------- ---------- ---------- -------- --------
Total assets $1,530,891 $1,240,356 $1,223,879 $1,203,041 $1,184,895 $993,455 $919,797
---------- ----------- ---------- ---------- ---------- -------- --------
Property, plant and
equipment, net $1,256,803 $1,005,679 $ 998,334 $ 907,829 $ 861,107 $756,344 $667,003
========== ========== ========== ========== ========== ======== ========
COMMON STOCK DATA
Annual dividend rate at
period-end $ 0.72 $ 0.70 $ 0.70 $ 0.68 $ 0.66 $ 0.64 $ 0.62
Cash dividends paid per
common share $ 0.71 $ 0.175 $ 0.685 $ 0.665 $ 0.645 $ 0.625 $ 0.605
Book value per common share $ 16.77 $ 15.18 $ 15.45 $ 13.21 $ 12.09 $ 11.23 $ 10.46
Market-to-book ratio at
period-end (%) 174 162 145 225 167 169 170
Yield at period-end (%) 2.5 2.8 3.1 2.3 3.3 3.4 3.5
Return on average common
stockequity excluding other
comprehensive
income(%)** 12.4 12.6 15.3 13.7 11.7 11.1 11.9
Return on average common
equity (%) 12.4 13.0 15.8 13.7 11.7 11.1 11.9
Price-to-earnings
(diluted) ratio at
period-end 14.3 -- 10.3 17.0 14.7 15.4 15.6
Shares outstanding at
period-end (000) 34,745 31,249 31,125 30,351 29,904 29,327 28,796
Price Range:
High $ 9,17029.99 $ 8,69525.20 $ 7,97540.25 $ 7,63030.38 $ 6,994
Cash dividends on preferred stock20.38 $ --22.50 $ --18.88
Low $ 7021.65 $ 8521.50 $ 85
- ----------------------------------------------------------------------------------------------------21.50 $ 14.69 $ 13.13 $ 15.13 $ 11.88
Close $ 29.10 $ 24.65 $ 22.50 $ 29.75 $ 20.25 $ 19.00 $ 17.78
Note: All information has been adjusted to reflect the 2-for-1 stock split
effective March 2, 1998
*On December 5, 2001, the Board of Directors of the Company approved a change in
the Company's fiscal year end from September 30 to December 31, effective
January 1, 2002. A transition report was filed on Form 10-Q for the period
October 1, 2001 to December 31, 2001.
**The comparable generally accepted accounting principle measure is return on
average common equity.
12
SELECTED BUSINESS SEGMENT DATA
Energen Corporation
Three Months
YEAR ENDED Ended Year Ended
DECEMBER 31, December 31, September 30,
(dollars in thousands) 2002 2001* 2001
------------ ------------ -------------
OIL AND GAS OPERATIONS
Operating revenues from
continuing operations
Natural gas $150,899 $35,324 $141,505
Oil 75,426 12,375 48,016
Natural gas liquids 22,849 4,533 26,011
Other 3,570 (2,746) 7,980
-------- ------- --------
Total assets $335,267 $308,905 $264,548 $258,902 $246,573
Long-term debt $100,000$252,744 $49,486 $223,512
-------- ------- --------
Production volumes from continuing
operations
Natural gas (MMcf) 47,776 11,886 45,847
Oil (MBbl) 3,139 512 2,019
Natural gas liquids (MBbl) 1,792 450 1,477
-------- ------- --------
Production volumes from continuing
operations (MMcfe) 77,360 17,656 66,823
-------- ------- --------
Total production volumes (MMcfe) 77,973 18,022 68,478
-------- ------- --------
Proved reserves
Natural gas (MMcf) 803,748 714,395 627,051
Oil (MBbl) 49,833 19,128 20,878
Natural gas liquids (MBbl) 26,697 25,944 24,931
-------- ------- --------
Other data from continuing operations
Depreciation and amortization $ 84,39171,405 $16,351 $ 43,91253,846
Capital expenditures $305,476 $25,052 $136,886
Operating income $ 60,97978,416 $ 66,307
Preferred stock3,243 $ --72,425
-------- ------- --------
NATURAL GAS DISTRIBUTION
Operating revenues
Residential $277,088 $63,724 $367,109
Commercial and industrial-small 104,247 22,445 147,636
Transportation 38,395 9,765 33,972
Other 4,701 744 5,145
-------- ------- --------
Total $424,431 $96,678 $553,862
-------- ------- --------
Gas delivery volumes (MMcf)
Residential 26,358 5,128 31,064
Commercial and industrial-small 11,838 2,193 14,054
Transportation 59,644 12,973 53,989
-------- ------- --------
Total 97,840 20,294 99,107
-------- ------- --------
Average number of customers
Residential 425,630 422,461 428,663
Commercial, industrial and
transportation 35,601 35,161 35,882
-------- ------- --------
Total 461,231 457,622 464,545
-------- ------- --------
Other data
Depreciation and amortization $ --33,682 $ --8,151 $ 1,80030,933
Capital expenditures $ 1,800
====================================================================================================65,815 $12,873 $ 56,090
Operating income $ 59,370 $ 8,034 $ 50,288
-------- ------- --------
Year Ended Year Ended Year Ended Year Ended
September 30, September 30, September 30, September 30,
(dollars in thousands) 2000 1999 1998 1997
------------- ------------- ------------- -------------
OIL AND GAS OPERATIONS
Operating revenues from
continuing operations
Natural gas $118,271 $116,555 $93,958 $59,474
Oil 39,220 35,207 20,472 13,199
Natural gas liquids 22,662 7,207 6,977 5,762
Other 5,095 8,419 7,051 5,265
-------- -------- -------- --------
Total $185,248 $167,388 $128,458 $83,700
-------- -------- -------- --------
Production volumes from continuing
operations
Natural gas (MMcf) 47,441 52,754 42,432 28,995
Oil (MBbl) 2,140 2,937 1,378 734
Natural gas liquids (MBbl) 1,411 757 817 502
-------- -------- -------- --------
Production volumes from continuing
operations (MMcfe) 68,756 74,919 55,599 36,412
-------- -------- -------- --------
Total production volumes (MMcfe) 70,482 77,159 57,353 36,980
-------- -------- -------- --------
Proved reserves
Natural gas (MMcf) 777,456 740,001 542,039 544,283
Oil (MBbl) 24,518 24,719 19,845 9,128
Natural gas liquids (MBbl) 26,007 21,937 17,292 12,378
-------- -------- -------- --------
Other data from continuing operations
Depreciation and amortization $ 56,226 $ 59,322 $ 54,192 $ 35,729
Capital expenditures $ 67,090 $198,577 $120,991 $239,718
Operating income $ 47,568 $ 31,089 $ 20,299 $ 14,295
-------- -------- -------- --------
NATURAL GAS DISTRIBUTION
Operating revenues
Residential $233,839 $209,263 $241,964 $237,022
Commercial and industrial-small 88,521 77,254 89,361 87,477
Transportation 35,312 34,541 35,246 33,080
Other 8,489 4,496 3,369 5,405
-------- -------- -------- --------
Total $366,161 $325,554 $369,940 $362,984
-------- -------- -------- --------
Gas delivery volumes (MMcf)
Residential 26,069 24,751 31,079 28,357
Commercial and industrial-small 12,092 11,662 13,705 12,554
Transportation 70,534 66,356 70,563 65,622
-------- -------- -------- --------
Total 108,695 102,769 115,347 106,533
-------- -------- -------- --------
Average number of customers
Residential 429,368 425,937 423,602 422,878
Commercial, industrial and
transportation 35,526 35,111 34,782 34,485
-------- -------- -------- --------
Total 464,894 461,048 458,384 457,363
-------- -------- -------- --------
Other data
Depreciation and amortization $28,708 $26,730 $25,153 $23,486
Capital expenditures $67,073 $46,029 $54,168 $43,277
Operating income $49,063 $46,565 $41,663 $38,792
-------- -------- -------- --------
13
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This information is incorporatedCRITICAL ACCOUNTING POLICIES
The Company's consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America.
Management has identified the following critical accounting policies in the
application of existing accounting standards or in the implementation of new
standards that involve significant judgements and estimates by referencethe Company:
OIL AND GAS OPERATIONS
ACCOUNTING FOR NATURAL GAS AND OIL PRODUCING ACTIVITIES AND RELATED RESERVES:
The Company utilizes the successful efforts method of accounting for its natural
gas and oil producing activities. Under this accounting method, acquisition and
development costs of proved properties are capitalized and amortized on a
units-of-production basis over the remaining life of total proved and proved
developed reserves.
Estimates of physical quantities of oil and gas reserves are determined by
Company engineers and, in some cases, by third-party experts. Proved oil and gas
reserves are the estimated quantities of crude oil, natural gas and natural gas
liquids that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Accordingly, these estimates do not include
probable or possible reserves. Estimated oil and gas reserves are based on
currently available reservoir data and are subject to future revision. The
Company's production of undeveloped reserves require the installation or
completion of related infrastructure facilities such as pipelines and the
drilling of development wells.
Changes in oil and gas prices, operating costs and expected performance from the
1995 Annual Reportproperties will result in a revision to Stockholders, pages 25-33,the amount of estimated reserves held by
the Company. If reserves are revised upward, earnings could be affected due to
lower depreciation and depletion expense per unit of production. Likewise, if
reserves are revised downward, earnings could be affected due to higher
depreciation and depletion expenses or due to an immediate writedown of the
property's book value if an impairment is warranted. The table below reflects
the estimated effect on depreciation and depletion expense for 2003 of changes
in oil and gas reserve quantities from the reported amounts at December 31,
2002.
Percentage Change in Oil & Gas Reserves
From Reported Reserves as of December 31, 2002
(dollars in thousands) +10% +5% -5% -10%
------- ------- ------- -------
Estimated change in depreciation expense for
the year ended December 31, 2003, net of tax $(4,300) $(2,100) $ 2,400 $ 5,200
------- ------- ------- -------
ASSET IMPAIRMENTS: Oil and gas developed and undeveloped properties periodically
are assessed for possible impairment, generally on a field-by-field basis, using
the estimated undiscounted future cash flows of each field. Impairment losses
are recognized when the estimated undiscounted future cash flows are less than
the current net book values of the properties in a field. The Company monitors
its oil and gas properties as well as the market and business environments in
which it operates and makes assessments about events that could result in
potential impairment issues. Such potential events may include, but are not
limited to, substantial commodity price declines, unanticipated increased
operating costs, and lower-than-expected production performance from the
properties. If a material event occurs, Energen Resources makes an estimate of
undiscounted future cash flows to determine whether the asset is impaired. If
the asset is impaired, the Company will record an impairment loss for the
difference between the net book value of the properties and the fair value of
the properties. The fair value of the properties typically is estimated using
discounted cash flow.
Cash flow and fair value estimates require Energen Resources to make projections
and assumptions for pricing, demand, competition, operating costs, legal and
regulatory issues, discount rates and other factors for many years into the
future. These variables can, and often do, differ from the estimate and can have
a positive or negative
14
impact on the Company's need for impairment or of the amount of impairment. In
addition, further changes in the economic and business environment can impact
the Company's original and ongoing assessments of potential impairment.
NATURAL GAS DISTRIBUTION
REGULATED OPERATIONS: Alagasco applies SFAS No. 71, "Accounting for the Effects
of Certain Types of Regulation," to its regulated operations. This standard
requires a cost to be capitalized as a regulatory asset that otherwise would be
charged to expense if it is probable that the cost is recoverable in the future
through regulated rates. Likewise, if current recovery is provided for a cost
that will be incurred in the future, SFAS No. 71 requires the cost to be
recognized as a regulatory liability. The Company anticipates SFAS No. 71 will
continue as the applicable accounting standard for its regulated operations.
Alagasco's rate setting methodology, Rate Stabilization and Equalization, has
been in effect since 1983.
CONSOLIDATED
EMPLOYEE BENEFIT PLANS: Determining the Company's obligations to employees under
its defined benefit pension plan requires the use of estimates. The calculation
of the liability related to the Company's defined benefit pension plan requires
assumptions regarding the appropriate weighted average discount rate, estimated
rate of increase in the compensation level of its employee base and the expected
long-term rate of return on the plans' assets. The selection and use of such
assumptions affects the amount of expense recorded in the Company's financial
statements related to its defined benefit pension plan. The discount rate for
pension cost purposes is the rate at which pension obligations could be
effectively settled. At December 31, 2002 the discount rate used for actuarial
purposes was 6.75 percent. A hypothetical basis point change in the discount
rate would impact total pension expense by approximately $560,000. The assumed
rate of return on assets is the weighted average of expected long-term asset
assumptions. At December 31, 2002, the return on assets used for actuarial
purposes was 9 percent. A hypothetical 25 basis point change in the return on
assets would impact total pension expense by approximately $245,000.
CHANGE IN YEAR END
On December 5, 2001, the Board of Directors of the Company approved a change in
the Company's fiscal year end from September 30 to December 31, effective
January 1, 2002. A transition report was filed on Form 10-Q for the period
October 1, 2001 to December 31, 2001. Alagasco will continue on a September 30
fiscal year for rate-setting purposes (rate year) and will report on a calendar
year for the Securities and Exchange Commission and all other financial
accounting reporting purposes.
RESULTS OF OPERATIONS
CONSOLIDATED NET INCOME
Energen Corporation's net income for the year ended December 31, 2002 totaled
$68.6 million, or $2.03 per diluted share compared to fiscal year ended
September 30, 2001 net income of $67.9 million, or $2.18 per diluted share. This
7 percent decrease in earnings per diluted share (EPS) reflects an increase in
the number of shares outstanding related to the acquisition of oil and gas
properties in the Permian Basin in April 2002. Energen Resources Corporation,
Energen's oil and gas subsidiary, had a slight decrease in earnings for the 12
months ended December 31, 2002, as compared with the 12 months ended September
30, 2001. Alabama Gas Corporation (Alagasco), Energen's utility subsidiary,
generated a 6 percent increase in net income in the same period comparisons. For
the 12 months ended September 30, 2000, Energen reported earnings of $53
million, or $1.75 per diluted share.
2002 VS 2001: For the year ended December 31, 2002, Energen Resources' net
income totaled $41.2 million as compared with $42.6 million for the 12 months
ended September 30, 2001. Net income in the current year included a non-cash
benefit of $5.7 million after-tax ($0.17 per diluted share) associated with its
previous hedge position with Enron North America Corp. (Enron) and a one-time
charge of $2.2 million after-tax ($0.07 per diluted share), reflecting the
cumulative effect on prior years of the adoption of SFAS No. 143, "Accounting
for Asset Retirement Obligations." Energen Resources' income from continuing
operations in 2002 totaled $43.2 million as compared with $40.8 million in
fiscal 2001, primarily due to a 15.8 percent increase in production volumes
related to an acquisition of oil properties in the Permian Basin in April 2002.
The primary negative influences on income from
15
operations were increased lease operating expense and increased depreciation,
depletion and amortization (DD&A) expense.
Alagasco's earnings increased to $27.6 million in 2002 from $26 million in
fiscal year 2001 as a result of the utility having increased earnings on a
higher level of equity. Alagasco achieved a return on average equity (ROE) of
12.3 percent in both 2002 and 2001.
2001 VS 2000: Energen Resources' net income in fiscal 2001 rose 55.2 percent to
$42.6 million. Energen Resources' income from continuing operations in fiscal
2001 totaled $40.8 million as compared with $26.9 million in fiscal 2000,
primarily due to a 23.3 percent increase in realized sales prices for natural
gas, oil and natural gas liquids production. The significantly higher realized
commodity prices more than compensated for the negative impact of increased
lease operating expense and a 1.9 Bcfe production decrease. Earnings in fiscal
year 2000 were negatively affected by a $2.2 million ($0.07 per diluted share)
after-tax writedown under SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of," for certain oil
and gas properties resulting from a downward reserve revision.
Alagasco's earnings declined 1.2 percent from $26.3 million in fiscal 2000 to
$26 million in fiscal year 2001. This slight decrease in income was primarily a
result of increased bad debt expense from significantly colder weather and
higher natural gas prices during the fiscal 2001 winter as well as industrial
load loss resulting from an economic slowdown. Alagasco achieved a return on
average equity (ROE) of 12.3 percent in 2001 as compared to 13.4 percent in
2000.
THREE MONTHS ENDED DECEMBER 31, 2001 VS THREE MONTHS ENDED DECEMBER 31, 2000:
Energen's net income totaled $3.7 million ($0.12 per diluted share) for the
three months ended December 31, 2001, compared to net income of $13.7 million
($0.44 per diluted share) recorded in the same period of 2000. Energen Resources
realized net income from continuing operations of $1.1 million in the December
31, 2001 transition quarter as compared with $9.3 million in the same quarter in
the previous year largely due to a one-time non-cash write-off of $5.5 million
after-tax ($0.17 per diluted share) associated with its hedge position with
Enron. Also negatively impacting net income in the transition quarter were
increased DD&A expense, a $1.7 million writedown on property held for sale and
lower natural gas liquids prices. Energen's natural gas utility, Alagasco,
reported net income of $2.7 million in the transition quarter as compared to $4
million in the same period in the previous year primarily due to increased bad
debt expense as well as a decline in cycle and industrial gas usage.
OPERATING INCOME
Consolidated operating income in 2002, 2001 and 2000 totaled $136 million, $121
million and $95 million, respectively. This significant growth in operating
income was influenced by strong financial performance from Energen Resources
under Energen's diversified growth strategy, implemented in fiscal 1996.
Alagasco also contributed to this growth in operating income consistent with an
increase in the level of equity upon which it has been able to earn a return.
OIL AND GAS OPERATIONS: Revenues from oil and gas operations rose significantly
in the current year largely as a result of increased production volumes related
to the acquisition of oil properties in the Permian Basin. During 2002,
production from continuing operations increased 15.8 percent to 77.4 Bcfe.
Natural gas production increased 4.2 percent to 47.8 Bcf and oil volumes rose
55.5 percent to 3,139 MBbl. Production of natural gas liquids increased 21.3
percent to 1,792 MBbl. Including the non-cash benefit from the former Enron
hedges, realized gas prices rose 2.3 percent to $3.16 per Mcf, while realized
oil prices increased 1.1 percent to $24.03 per barrel. Natural gas liquids
prices fell 27.6 percent to an average price of $12.75 per barrel.
In fiscal 2001, revenues from oil and gas continuing operations increased
largely as a result of significantly higher commodity prices as compared to the
previous fiscal year. Realized gas prices rose 24.1 percent to $3.09 per Mcf,
while realized oil prices increased 29.7 percent to $23.78 per barrel. Natural
gas liquids prices increased 9.7 percent to an average price of $17.61 per
barrel. During 2001, production from continuing operations declined slightly to
66.8 Bcfe as natural gas production decreased 3.4 percent to 45.8 Bcf and oil
volumes declined 5.7 percent to 2,019 MBbl. Production of natural gas liquids
increased 4.7 percent to 1,477 MBbl. This 1.9 Bcfe
16
decrease in production largely was due to normal production declines in Energen
Resources' coalbed methane and south Louisiana properties. Drilling in the San
Juan and Permian basins and in the north Louisiana/east Texas area served to
replace aggregate production in these areas.
Coalbed methane operating fees are calculated as a percentage of net proceeds on
certain properties, as defined by the related operating agreements, and vary
with changes in natural gas prices, production volumes and operating expenses.
Revenues from operating fees were $4.8 million, $7.6 million and $4.3 million in
2002, 2001 and 2000, respectively.
DECEMBER 31, September 30, September 30,
Years ended (in thousands, except sales price data) 2002 2001 2000
------------ ------------- -------------
Revenues from continuing operations
Natural gas production $ 150,899 $ 141,505 $ 118,271
Oil production 75,426 48,016 39,220
Natural gas liquids production 22,849 26,011 22,662
Operating fees 4,847 7,618 4,262
Other (1,277) 362 833
-------- -------- --------
Total revenues from continuing operations $ 252,744 $ 223,512 $ 185,248
-------- -------- --------
Production volumes from continuing operations
Natural gas (MMcf) 47,776 45,847 47,441
Oil (MBbl) 3,139 2,019 2,140
Natural gas liquids (MBbl) 1,792 1,477 1,411
-------- -------- --------
Average sales price including effects of hedging
Natural gas (per Mcf) $ 3.16 $ 3.09 $ 2.49
Oil (per barrel) $ 24.03 $ 23.78 $ 18.33
Natural gas liquids (per barrel) $ 12.75 $ 17.61 $ 16.06
-------- -------- --------
Average sales price excluding effects of hedging
Natural gas (per Mcf) $ 2.96 $ 4.86 $ 3.06
Oil (per barrel) $ 24.75 $ 27.46 $ 26.45
Natural gas liquids (per barrel) $ 12.75 $ 17.61 $ 16.06
-------- -------- --------
Energen Resources may, in the ordinary course of business, be involved in the
sale of developed or undeveloped properties. With respect to developed
properties, sales may occur as a result of, but not limited to, disposing of
non-strategic or marginal assets and accepting offers where the buyer gives
greater value to a property than does Energen Resources. The Company is required
to reflect gains and losses on the dispositions of these assets, the writedown
of certain properties held-for-sale, and income or loss from the operations of
the associated held-for-sale properties as discontinued operations under the
provisions of SFAS No. 144, which was adopted as of January 1, 2002. Energen
Resources recorded in 2002 a pre-tax gain of $0.9 million in total income from
discontinued operations from the sale of properties and adjustments to the fair
value of properties being held-for-sale. In 2001, prior to the adoption of SFAS
No. 144, Energen Resources recorded in operating revenues a net pre-tax gain
from the sale of properties and adjustments to the fair value of properties held
for sale of $0.8 million. Pre-tax gains from the sale of properties of $1.1
million were recorded in operating revenues in 2000.
Operations and maintenance (O&M) expense increased $10.3 million and $9.9
million in 2002 and 2001, respectively. Lease operating expense in 2002 rose
$7.6 million primarily due to the acquisition of oil and gas properties. In
2001, lease operating expense increased by $9.2 million largely due to
significantly higher operational costs driven by market conditions resulting
from increased commodity costs. In the current year, administrative expense
increased $3.5 million primarily due to labor related costs and additional cost
related to the property acquisition. Administrative expense increased $1.4
million in 2001. Exploration expense decreased $0.6 million in 2002 and $0.7
million in 2001, primarily due to reduced exploratory efforts.
DD&A expense increased $17.6 million in 2002 largely due to increased production
volumes and increased DD&A rates. In 2001, DD&A expense decreased $2.4 million
primarily due to lower production volumes and additional pre-tax DD&A expense of
$3.5 million recorded in 2000 to adjust the carrying amount of certain
properties to their
17
fair value based on expected future discounted cash flows (see Note 12). The
average depletion rate was $0.90 per Mcfe in 2002 as compared to $0.79 per Mcfe
in the prior year.
Energen Resources' expense for taxes other than income primarily reflected
production-related taxes. Energen Resources recorded severance taxes for 2002 of
$18.9 million. Severance taxes in 2001 were $23.9 million as a result of
increased commodity prices. In 2000, severance taxes were $17.3 million.
OIL AND GAS OPERATIONS - TRANSITION PERIOD: Revenues from oil and gas continuing
operations declined 9.8 percent to $49.5 million for the three months ended
December 31, 2001, largely as a result of lower natural gas liquids prices. In
the transition quarter, realized gas prices increased 8.4 percent to $2.97 per
Mcf, while realized oil prices rose 7.8 percent to $24.19 per barrel. Natural
gas liquids prices decreased 51.4 percent to an average price of $10.07 per
barrel.
Natural gas production in the transition quarter increased slightly to 11.9 Bcf,
while oil volumes decreased slightly to 512 MBbl. Natural gas liquids production
increased 13.9 percent to 450 MBbl. Natural gas comprised nearly 70 percent of
Energen Resources' production in the transition quarter.
DECEMBER 31, December 31,
Three months ended (in thousands, except sales price data) 2001 2000
------------ ------------
Revenues from continuing operations
Natural gas production $ 35,324 $32,316
Oil production 12,375 11,586
Natural gas liquids production 4,533 8,180
Operating fees 913 2,225
Other (3,659) 555
-------- -------
Total revenues from continuing operations $ 49,486 $54,862
-------- -------
Production volumes from continuing operations
Natural gas (MMcf) 11,886 11,796
Oil (MBbl) 512 516
Natural gas liquids (MBbl) 450 395
-------- -------
Average sales price including effects of hedging
Natural gas (per Mcf) $ 2.97 $ 2.74
Oil (per barrel) $ 24.19 $ 22.45
Natural gas liquids (per barrel) $ 10.07 $ 20.70
-------- -------
Average sales price excluding effects of hedging
Natural gas (per Mcf) $ 2.35 $ 5.15
Oil (per barrel) $ 19.79 $ 30.65
Natural gas liquids (per barrel) $ 10.07 $ 20.70
-------- -------
Prior to the adoption of SFAS No. 144, Energen Resources recorded in operating
revenues a pre-tax loss of $3.4 million for the current transition quarter from
the sale of properties and adjustments to the fair value of properties
held-for-sale as compared to a pre-tax gain of $0.8 million in the prior year
quarter on the sale of various properties.
O&M expense increased $8.6 million for the transition quarter ended December 31,
2001, largely due to the one-time non-cash writedown of $8.7 million pre-tax
associated with Energen Resources' hedge position with Enron. Lease operating
expenses increased by $0.4 million for the transition quarter while exploration
expense remained relatively stable.
Energen Resources' DD&A expense for the period rose $4.5 million primarily
driven by the impact of market declines in commodity prices. The average
depletion rate for the transition quarter was $0.91 as compared to $0.67 for the
same period in the previous year.
18
Energen Resources' expense for taxes other than income taxes primarily reflected
production-related taxes that were $3.3 million lower in the transition quarter
primarily as a result of the significantly decreased commodity market prices.
NATURAL GAS DISTRIBUTION: As discussed more fully in Note 2, Alagasco is subject
to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002,
the APSC issued an order to extend the Company's rate-setting mechanism. Under
the terms of that extension, RSE will continue after January 1, 2008, unless,
after notice to the Company and a hearing, the Commission votes to either modify
or discontinue its operation.
Alagasco generates revenues through the sale and transportation of natural gas.
The transportation rate does not contain an amount representing the cost of gas,
and Alagasco's rate structure allows similar margins on transportation and sales
gas. Weather can cause variations in space heating revenues, but operating
margins essentially remain unaffected due to a real-time temperature adjustment
mechanism that allows Alagasco to adjust customer bills monthly to reflect
changes in usage due to departures from normal temperatures. The temperature
adjustment applies to residential, small commercial and small industrial
customers.
Alagasco's natural gas and transportation sales revenues totaled $424.4 million,
$553.9 million and $366.2 million in 2002, 2001 and 2000, respectively. Lower
commodity gas costs and weather that was 13.1 percent warmer than in the prior
year contributed to the decrease in sales revenue in the current year. Sales
revenue in fiscal 2001 rose due to significantly higher commodity gas costs as
well as weather that was 29.9 percent colder than in fiscal year 2000.
In the current year, residential sales volumes decreased 15.1 percent primarily
due to the impact of warmer weather on throughput. Small commercial and
industrial volumes, also sensitive to weather, decreased 15.8 percent.
Transportation volumes rose 10.5 percent, due to the previous period's
significantly higher natural gas prices and a general economic weakness. During
2001, significantly colder weather in Alagasco's service territory caused a 19.2
percent increase in residential sales volumes and a 16.2 percent increase in
small commercial and industrial sales volumes. Transportation volumes decreased
23.5 percent, primarily due to the prior-year closing of a steel manufacturing
plant and reduced consumption resulting from an economic downturn during the
year.
In 2002, significantly lower commodity gas costs along with decreased purchased
volumes due to warmer weather resulted in a 41.9 percent decrease in cost of
gas. Higher commodity cost of gas, including record high prices in fiscal year
2001, along with increased purchased volumes resulting from colder weather
generated a 111.5 percent increase in cost of gas for fiscal year 2001.
O&M expense at the utility increased 3.1 percent in 2002 primarily due to higher
insurance and labor-related costs partially offset by reduced bad debt expense
and marketing costs. In fiscal 2001, O&M expense increased 1.5 percent primarily
as a result of increased bad debt expense and insurance costs largely offset by
reduced marketing and labor-related costs. The increase in O&M expense per
customer was above the inflation-based Cost Control Measurement (CCM)
established by the APSC as part of the utility's rate-setting mechanism, for the
rate year ended September 30, 2002; as a result, three quarters of the
difference, or $0.3 million pre-tax, was returned to the customers through RSE
(see Note 2). In 2001 and 2000, the increase in O&M expense on a per-customer
basis fell within the CCM.
Consistent with growth in the utility's depreciable base, depreciation expense
rose 8.9 percent in 2002 and 7.8 percent in 2001. Alagasco's expense for taxes
other than income primarily reflects various state and local business taxes as
well as payroll-related taxes. State and local business taxes generally are
based on gross receipts and fluctuate accordingly.
19
DECEMBER 31, September 30, September 30,
Years ended (in thousands) 2002 2001 2000
------------ ------------- -------------
Natural gas transportation and sales revenues $ 424,431 $ 553,862 $ 366,161
Cost of natural gas (191,479) (329,572) (155,841)
Revenue taxes (21,591) (28,766) (19,749)
--------- --------- ---------
Natural gas transportation and sales margin $ 211,361 $ 195,524 $ 190,571
--------- --------- ---------
Natural gas sales volumes (MMcf)
Residential 26,358 31,064 26,069
Commercial and industrial-small 11,838 14,054 12,092
--------- --------- ---------
Total natural gas sales volumes 38,196 45,118 38,161
Natural gas transportation volumes (MMcf) 59,644 53,989 70,534
--------- --------- ---------
Total deliveries (MMcf) 97,840 99,107 108,695
--------- --------- ---------
NATURAL GAS DISTRIBUTION - TRANSITION PERIOD: Natural gas distribution revenues
decreased $22.4 million for the transition quarter ended December 31, 2001,
largely due to a decrease in the commodity cost of gas as well as to a decrease
in weather-related sales volumes and gas usage volumes. For the quarter, weather
that was 30.1 percent warmer than the same period last year contributed to a
29.1 percent decrease in residential sales volumes and a 34.3 percent decrease
in small commercial and industrial customer sales volumes. Transportation
volumes decreased 6.3 percent primarily due to reduced consumption resulting
from a general economic weakness in the transition period. Lower commodity gas
prices along with decreased gas purchase volumes contributed to a 32.5 percent
decrease in cost of gas for the quarter.
O&M expense increased 3.2 percent in the transition quarter primarily due to
increased bad debt expense partially offset by reduced labor-related and
marketing costs. A 7.9 percent increase in depreciation expense in the
three-months ended December 31, 2001 primarily was due to normal growth of the
utility's distribution system. Taxes other than income taxes primarily reflected
various state and local business taxes as well as payroll-related taxes. State
and local business taxes generally are based on gross receipts and fluctuate
accordingly.
DECEMBER 31, December 31,
Three months ended (in thousands) 2001 2000
------------ ------------
Natural gas transportation and sales revenues $ 96,678 $ 119,126
Cost of natural gas (45,651) (67,679)
Revenue taxes (4,969) (6,281)
-------- ---------
Natural gas transportation and sales margin $ 46,058 $ 45,166
-------- ---------
Natural gas sales volumes (MMcf)
Residential 5,128 7,230
Commercial and industrial-small 2,193 3,337
-------- ---------
Total natural gas sales volumes 7,321 10,567
Natural gas transportation volumes (MMcf) 12,973 13,851
-------- ---------
Total deliveries (MMcf) 20,294 24,418
-------- ---------
NON-OPERATING ITEMS
CONSOLIDATED: Interest expense in 2002 increased $1.6 million and was influenced
by increased short-term debt at Energen, primarily related to Energen Resources'
acquisition of Permian Basin properties in April 2002, as well as Alagasco's
issuance of $40 million of 6.25% Notes and $35 million of 6.75% Notes in August
2001 (the Notes). Fiscal 2001 interest expense increased $4.3 million primarily
due to $150 million of medium term notes (MTNs) issued by Energen in December
2000 and, in part, from the issuance of the Notes. The average daily outstanding
balance under short-term credit facilities was $85.6 million in 2002. The
average daily outstanding balance under short-term credit facilities was $80.7
million in fiscal year 2001 as compared to $146.8 million in fiscal year 2000.
The Company's effective tax rates in 2002, 2001 and 2000 were lower than
statutory federal tax rates primarily due to the recognition of nonconventional
fuels tax credits and the amortization of investment tax credits.
Nonconventional fuels tax credits were generated annually on qualified
production through December 31, 2002.
20
Income tax expense increased in 2002 and 2001 primarily due to higher pre-tax
income. The Company recognized $14.2 million, $13.6 million and $14.4 million in
nonconventional fuels tax credits in 2002, 2001 and 2000, respectively. The
nonconventional fuels tax credits are no longer generated effective December 31,
2002, due to changes in the tax law. As of December 31, 2002, the amount of
minimum tax credit that has been previously recognized and can be carried
forward indefinitely to reduce future regular tax liability is $64.8 million.
TRANSITION PERIOD: Interest expense for the Company increased $0.4 million for
the transition quarter. Influencing the increase in interest expense for the
transition quarter was the issuance of MTNs issued by Energen in December 2000
and the issuance of the Notes by Alagasco in August 2001. The proceeds from the
Notes were used for repayment of borrowings under Energen's short-term credit
facilities incurred as a result of the growth at Energen Resources and for
general corporate purposes at Alagasco.
The Company's effective tax rate was lower than the statutory federal tax rate
primarily due to the recognition of nonconventional fuels tax credits and the
amortization of investment tax credits. Income tax expense decreased in quarter
comparisons primarily as a result of lower consolidated pre-tax income slightly
offset by higher nonconventional fuels tax credits of $1.2 million. The increase
in credit recognition reflected the annualized effective rate applied on an
interim basis in the three months ended December 31, 2000, as compared to the
transition period which was presented as a stand alone tax period in the current
quarter. The effective tax rate utilized in computing income tax expense
reflects financial recognition of $3.5 million of nonconventional fuels tax
credits as produced during the transitional quarter.
FINANCIAL POSITION AND LIQUIDITY
The Company's net cash from operating activities totaled $213.5 million, $156.5
million and $105 million in 2002, 2001 and 2000, respectively. In 2002,
operating cash flow benefited from significantly higher production volumes
related to Energen Resources' property acquisition and decreased storage
inventory balances at Alagasco. Operating cash flow in 2001 benefited from
significantly higher realized commodity prices at Energen Resources. Working
capital needs at Alagasco in 2001 were affected by increased gas costs and
colder-than-normal weather resulting in higher storage inventory balances. Other
working capital items, which primarily are the result of changes in throughput
and the timing of payments, combined to create the remaining increases for all
years.
During 2002, the Company made net investments of $268.2 million. Energen
Resources invested $184.2 million for property acquisitions, $122.5 million for
the development of proved properties and $0.1 million for exploration. In April
2002, Energen Resources completed its purchase of oil and gas properties located
in the Permian Basin in west Texas from First Permian, L.L.C. (First Permian)
for approximately $120 million in cash and 3,043,479 shares of the Company's
common stock. The total acquisition approximated $184 million and added 227 Bcfe
of reserves. Energen Resources drilled 232 gross development wells incurring
approximately $77 million. Energen Resources sold or traded certain properties
during the current year, resulting in cash proceeds of $17 million. Utility
expenditures in 2002 totaled $65.8 million and primarily represented system
distribution expansion and support facilities, including, information technology
application projects. Cash used in investing activities totaled $174.4 million
in 2001. During fiscal 2001, Energen Resources invested $34.3 million for
property acquisitions, $103.6 million for development of proved properties and
$1.2 million for exploration. Energen Resources drilled 140 gross development
wells spending approximately $70 million. Energen Resources sold or traded
certain properties during fiscal 2001, resulting in cash proceeds of $17.3
million. Utility expenditures for fiscal 2001 totaled $56.1 million, including
approximately $3 million for a municipal acquisition. Cash used in investing
activities totaled $131.7 million in 2000. Energen Resources invested $2.4
million for property acquisitions, $66.7 million for development and $1.2
million for exploration during fiscal 2000. Energen Resources drilled 141 gross
development wells incurring approximately $38 million. Utility expenditures in
2000 totaled $67.1 million.
During 2002, the Company added approximately 162 Bcfe of reserves. These reserve
additions are primarily the result of unit downspacing, which increases the
number of available drilling locations, for certain wells in the Black Warrior
and San Juan basins. Energen Resources' added approximately 50 Bcfe and 76 Bcfe
of reserves in fiscal year 2001 and 2000, respectively.
21
Net cash provided by financing activities totaled $53 million in 2002. In the
current year, the Company utilized $85.9 million in short-term credit
facilities to finance Energen Resources' acquisition strategy. Long-term debt
was reduced by $21.2 million, including the retirement of the Series 1993 Notes
for $7.8 million. Net cash provided by financing activities totaled $19.4
million in 2001. In August 2001 Alagasco issued 6.25% Notes for $40 million,
redeemable September 1, 2016, and 6.75% Notes for $35 million, redeemable
September 1, 2031, and in December 2000, Energen issued $150 million of
long-term debt redeemable December 15, 2010. The $223.8 million in net proceeds
were used to repay short-term borrowings incurred to finance Energen Resources'
growth activities and to repay additional borrowings by the utility as a result
of higher capital expenditures related to replacement of liquifaction equipment
and for general corporate purposes. The proceeds also were used to reduce
long-term debt by $36.3 million, including the retirement of the 8% Debentures
for $18.3 million. Net cash used in financing activities totaled $114.9 million
in 2000 resulting primarily from fluctuations in the amount and timing of
short-term debt at year-end. The Company borrowed $140.9 million at September
30, 1999 to invest in short-term federal obligations for tax planning purposes
that were sold in early October 2000 with the proceeds used to repay the
related debt. For each of the years, net cash used in financing activities also
reflected dividends paid to common stockholders and the issuance of common
stock through the dividend reinvestment and direct stock purchase plan and the
employee savings plans.
TRANSITION PERIOD: Cash flows from operations for the transition quarter were
$21.4 million compared to $20.7 million in the three months ended December 31,
2000. The decreased net income during the period was offset by changes in
working capital items, which are highly influenced by throughput, changes in
weather, and timing of payments.
The Company had a net investment of $35.7 million through the three months
ended December 31, 2001, primarily in additions of property, plant and
equipment. Energen Resources invested $25.1 million in capital expenditures
primarily related to the development of oil and gas properties. Utility capital
expenditures totaled $12.9 million in the quarter and primarily represented
system distribution expansion and support facilities. The Company had cash
proceeds of $2.3 million resulting from the sale of certain properties during
the transition period.
The Company's financing activities provided $15.5 million for the transition
quarter in net cash flows. Increased borrowings under Energen's short-term
credit facilities were used to finance Energen Resources' acquisition strategy
and general corporate needs at Alagasco.
CAPITAL EXPENDITURES
OIL AND GAS OPERATIONS: Energen Resources spent $546.6 million for capital
projects during the year ended December 31, 2002, the three months ended
December 31, 2001 and the years ended September 30, 2001 and 2000, $12.1
million of which was charged to income as exploration expense primarily due to
the writedown of a portion of an unproved leasehold. Property acquisition
expenditures totaled $221.2 million, development activities totaled $317.5
million, and exploratory expenditures totaled $2.7 million.
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------- ------------- -------------
Capital and exploration expenditures for:
Property acquisitions $184,177 $ 319 $ 34,316 $ 2,436
Development 122,494 24,757 103,574 66,717
Exploration 104 228 1,190 1,150
Other 1,880 464 1,477 1,343
-------- ------- -------- -------
Total 308,655 25,768 140,557 71,646
Less exploration expenditures charged
to income 3,179 716 3,671 4,556
-------- ------- -------- -------
Net capital expenditures $305,476 $25,052 $136,886 $67,090
======== ======= ======== =======
22
NATURAL GAS DISTRIBUTION: During the year ended December 31, 2002, the three
months ended December 31, 2001 and the years ended September 30, 2001 and 2000,
Alagasco invested $201.9 million for capital projects: $124 million for normal
expansion, replacements and support of its distribution system, $74.9 million
for support facilities, including the replacement of liquifaction equipment and
the development and implementation of information systems, and $3 million to
purchase a municipal gas system.
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Capital and expenditures for:
Renewals, replacements,
system expansion and other $43,029 $ 8,839 $36,340 $35,774
Support facilities 22,786 4,034 16,733 31,299
Municipal gas system acquisition -- -- 3,017 --
------- ------- ------- -------
Total $65,815 $12,873 $56,090 $67,073
======= ======= ======= =======
FUTURE CAPITAL RESOURCES AND LIQUIDITY
The Company plans to continue to implement its diversified growth strategy that
focuses on expanding Energen Resources' oil and gas operations through the
acquisition of producing properties with development potential while
maintaining the strength of the Company's utility foundation. For the five
calendar years ended December 31, 2002, Energen's EPS grew at an average
compound rate of 11.5 percent a year. Over the next five years, Energen is
targeting an average EPS growth rate over each rolling five-year period of 7
percent to 8 percent a year.
To finance Energen Resources' investment program, the Company expects to
utilize its short-term credit facilities to supplement internally generated
cash flow, with long-term debt and equity providing permanent financing.
Energen currently has available short-term credit facilities of $267 million to
help finance its growth plans and operating needs. As an acquisition company,
access to capital is an integral part of the Company's business plan. The
Company regularly provides information to corporate rating agencies related to
current business activities and future performance expectations. In February
2003, Moody's Investors Service confirmed Energen's debt rating as Baa1 and
Alagasco's debt rating as A1. Standard and Poor's last update in June 2002,
confirmed Energen's and Alagasco's rating as A- with a stable outlook. While
the Company expects to have ongoing access to it's short-term credit facilities
and the broader long-term markets, continued accessibility could be affected by
future economic and business conditions. Energen's management plans to utilize
increases in cash flows to help finance Energen Resources' acquisition
strategy.
In 2003, Energen Resources plans to invest approximately $158 million,
including $47 million in property acquisitions and related development and $111
million in other development and exploratory activities. Included in this $111
million is approximately $65 million for the development of previously
identified proved undeveloped reserves and exploratory exposure of
approximately $3 million. Capital investment at Energen Resources in 2004 is
expected to approximate $123 million for property acquisitions and related
development and $68 million for other development and exploration. Of this $68
million, development of previously identified proved undeveloped reserves is
estimated to be $35 million and exploratory exposure is estimated to be $3
million. Energen Resources' capital investment for oil and gas activities over
the five-year period ending December 31, 2007 is estimated to be approximately
$835 million, with $590 million for property acquisitions and related
development, $222 million for other development and $23 million for exploratory
and other activities. During the five year period, Energen Resources
anticipates spending approximately $120 million on development of previously
identified proved undeveloped reserves and incurring approximately $15 million
in exploratory exposure. During this period, the Company expects to issue
approximately $75 million in long-term debt and an estimated $25 million in
equity to replace short-term obligations and to provide permanent financing for
its acquisition strategy. The Company will also provide up to $14 million a
year from the issuance of common stock through the dividend reinvestment and
direct stock purchase plan, and through employee savings plans. Energen
Resources' continued ability to invest in property acquisitions will be
influenced significantly by industry trends, as the producing property
acquisition market historically has been cyclical. Notwithstanding the
estimated expenditures mentioned above, as an
23
acquisition oriented company Energen Resources continually evaluates
acquisition opportunities which arise in the marketplace and from time to time
may pursue acquisitions that meet Energen's acquisition strategy. These
acquisitions may alter the aforementioned financing requirements. Additionally,
Energen Resources may enter into negotiations to sell, trade or otherwise
dispose of properties which may reduce or eliminate the amount of additional
financing described above.
During 2003, Alagasco plans to invest approximately $57 million in utility
capital expenditures for normal distribution and support systems. Alagasco
maintains an investment in storage gas that is expected to average
approximately $42 million in 2003. Alagasco plans to invest approximately $55
million in utility capital expenditures during 2004. The utility anticipates
funding these capital requirements through internally generated capital and the
utilization of short-term credit facilities. Over the Company's five-year
planning period ending September 30, 2007, Alagasco anticipates capital
investments of approximately $265 million.
CONTRACTUAL CASH OBLIGATIONS AND OTHER COMMITMENTS
In the course of ordinary business activities, Energen enters into a variety of
contractual cash obligations and other commitments. The following table
summarizes the Company's significant contractual cash obligations, other than
hedging contracts as of December 31, 2002.
PAYMENTS DUE BY PERIOD
------------------------------------------------------------------------
LESS THAN AFTER 5
(in thousands) TOTAL 1 YEAR 1 - 3 YEARS 4 - 5 YEARS YEARS
-------- --------- ----------- ----------- ---------
Short-term cash obligations $113,000 $113,000 $ -- $ -- $ --
Long-term cash obligations (1) 537,533 23,000 40,000 22,000 452,533
Gas procurement contracts (2) 265,380 50,107 100,017 82,354 32,902
Operating leases 45,883 3,609 8,467 4,505 29,302
-------- -------- -------- -------- --------
Total contractual cash obligations $961,796 $189,716 $148,484 $108,859 $514,737
======== ======== ======== ======== ========
(1) Long-term cash obligations include $1.6 million of unamortized debt
discounts as of December 31, 2002.
(2) Certain of the Company's long-term contracts for the supply, storage
and delivery of natural gas include fixed charges that amount to approximately
$265.4 million through October 2010. The Company also is committed to purchase
minimum quantities of gas at market-related prices or to pay certain costs in
the event the minimum quantities are not taken. These purchase commitments are
approximately 55.4 billion cubic feet through October 2004.
Alagasco entered into an agreement with a financial institution whereby it can
sell on an ongoing basis, with recourse, certain installment receivables
related to its merchandising program up to a maximum of $20 million as further
described in Note 8.
OUTLOOK
OIL AND GAS OPERATIONS: Energen Resources plans to continue to implement its
acquisition and development program with capital spending in fiscal years 2003
and 2004 as outlined above. Production in 2003 is expected to be approximately
85 Bcfe, including 82.4 Bcfe of estimated production from proved reserves owned
at December 31, 2002. In 2004, production is estimated to reach approximately
87 Bcfe, including approximately 77 Bcfe produced from proved reserves
currently owned.
Nonconventional fuels tax credits were generated annually on qualified
production through December 31, 2002. To mitigate the effects of the tax credit
benefit, Energen Resources has replaced a portion of the tax credits with
revenue-generating property acquisitions and related development affecting
corporate earnings in 2003 and has increased the number of available drilling
locations through unit downspacing in the Black Warrior Basin.
In the event Energen Resources is unable to fully invest its planned
acquisition, development and exploratory expenditures, future operating
revenues, production and proved reserves could be negatively affected. Energen
24
Resources' major market risk exposure is in the pricing applicable to its oil
and gas production. Historically, prices received for oil and gas production
have been volatile because of seasonal weather patterns, national supply and
demand factors and general economic conditions. Crude oil prices also are
affected by quality differentials, worldwide political developments and actions
of the Organization of Petroleum Exporting Countries. Basis differentials, like
the underlying commodity prices, can be volatile because of regional supply and
demand factors, including seasonal variations and the availability and price of
transportation to consuming areas.
Energen Resources periodically enters into cash flow derivative commodity
instruments to hedge its exposure to oil, natural gas and natural gas liquids
price fluctuations. In addition, Alagasco enters into cash flow derivative
commodity instruments to hedge its exposure to price fluctuations on its gas
supply. Such instruments include regulated natural gas and crude oil futures
contracts traded on the New York Mercantile Exchange (NYMEX) and
over-the-counter swaps, collars and basis hedges with major energy derivative
product specialists. The counterparties to the commodity instruments are
investment banks and energy-trading firms. In some contracts, the amount of
credit allowed before Energen Resources or Alagasco must post collateral for
out-of-the-money hedges varies depending on the credit rating of the Company's
debt. In cases where this arrangement exists, generally the Company's credit
ratings must be maintained at investment grade status to have available
counterparty credit. All hedge transactions are subject to the Company's risk
management policy, approved by the Board of Directors, which does not permit
speculative positions. Energen Resources may hedge up to 80 percent of its
estimated annual production under this policy. As acquisitions are made,
Energen Resources may use futures, swaps and/or fixed-price contracts to hedge
commodity prices for up to 36 months in order to protect targeted returns.
As of December 31, 2002, 78 percent of Energen Resources' estimated 2003 gas
production, excluding anticipated acquisition volumes, was hedged or under
contract. These hedges included 30.9 Bcf of its estimated gas production at an
average NYMEX price of $4.13 per Mcf, 4.4 Bcf of basin-specific hedges at an
average contract price of $3.86 and 4.8 Bcf of gas production hedged with a
basin-specific collar price of $3.72 to $4.70 per Mcf. The Company also had
hedges in place for 2,478 MBbl or 68 percent of its estimated 2003 oil
production, excluding anticipated acquisition volumes, at an average NYMEX
price of $26.26 per barrel and 38 MMGal or 53 percent of its estimated 2003
natural gas liquids production at an average price of $0.42 per gallon. In
addition, the Company had hedged the basis difference on 11.7 Bcf of its
estimated 2003 gas production and 2,174 MBbl of its oil production. Subsequent
to December 31, 2002, Energen Resources entered into additional hedges for
2003, resulting in a total of 2,628 MBbl of its estimated 2003 oil production
hedged at an average NYMEX price of $26.36. The Company also entered into
additional basis hedges resulting in a total of 15.7 Bcf of basis hedges on its
estimated 2003 gas production and 2,271 MBbl of basis hedges on its estimated
2003 oil production.
At December 31, 2002, Energen Resources had entered into swaps for 6.5 Bcf of
its estimated 2004 gas production at an average NYMEX price of $4.02 per Mcf
and 2.4 Bcf of its estimated 2004 gas production hedged with a NYMEX collar
price of $4.05 to $4.44 per Mcf. Subsequent to December 31, 2002, Energen
Resources entered into additional hedges for 2004, resulting in a total of 8.9
Bcf of its estimated 2004 gas production hedged at an average NYMEX price of
$4.13 per Mcf, 120 MBbl of its estimated 2004 oil production hedged at an
average NYMEX price of $26.15 and 13.9 Bcf of basin-specific hedges at an
average contract price of $3.83 per Mcf. In addition, the Company hedged 30
MMGal of its estimated 2004 natural gas liquids production at an average price
of $0.41 per gallon. For 2005, Energen Resources had entered into swaps for 1.2
Bcf of its gas production at an average NYMEX price of $3.75 per Mcf.
The Company has prepared a sensitivity analysis to evaluate the hypothetical
effect that changes in the market value of crude oil, natural gas and natural
gas liquids may have on the fair value of its derivative instruments. This
analysis measured the impact on the commodity derivative instruments and,
thereby, did not consider the underlying exposure related to the commodity. At
December 31, 2002, the Company estimated that a 10 percent increase in the
commodities prices would have resulted in a $27.2 million change in the fair
value of open derivative contracts while a 10 percent decrease in the
commodities prices would have resulted in a $26.6 million change in the fair
value of open derivative contracts; however, gains and losses on derivative
contracts are expected to be similarly offset by sales at the spot market
price. At December 31, 2001 and September 30, 2001, the Company estimated that
a 10 percent change in the commodities prices would have resulted in a $2.1
million and a $6.9 million change, respectively, in the fair value of open
derivative contracts. Due to the short duration of the
25
contracts, the time value of money was not considered. The hypothetical change
in fair value was calculated by multiplying the difference between the
hypothetical price and the contractual price by the contractual volumes and did
not include the variance in basis or the impact of related taxes on actual cash
prices.
NATURAL GAS DISTRIBUTION: The extension of RSE in June 2002 provides Alagasco
the opportunity to continue earning an allowed ROE between 13.15 percent and
13.65 percent through January 1, 2008. Under the terms of that extension, RSE
will continue, unless, after notice to the Company and a hearing, the
Commission votes to either modify or discontinue its operation. As discussed in
Note 2,the utility's CCM is based in part on the number of residential
customers and the rate of inflation. Continued low inflation, significantly
higher gas prices resulting in increased bad debt expense and/or the lack of
customer growth could impact the utility's ability to manage its O&M expense
per customer sufficiently for the inflation-based cost control requirements of
RSE and may result in an average return on equity lower than the allowed range
of return due to the operation of the CCM. Over this period, Alagasco has the
potential for net income growth as the investment in additional utility plant
affects the level of equity required in the business. The utility continues to
rely on rate flexibility to effectively prevent bypass of its distribution
system. Even though the utility enjoys a market saturation rate higher than the
national average, customer growth in the service territory is limited.
On December 4, 2000, the APSC authorized Alagasco to engage in energy risk
management activities to manage the utility's cost of gas supply. As required
by SFAS No. 133, Alagasco recognizes all derivatives at their fair values as
either assets or liabilities on the balance sheet. Any gains or losses are
passed through to customers using the mechanisms of the GSA in compliance with
it's APSC-approved tariff. In accordance with SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation," Alagasco had recorded a regulatory
liability of $16.8 million representing the fair value of derivatives as of
December 31, 2002.
FORWARD-LOOKING STATEMENT AND RISK: Certain statements in this report express
expectations of future plans, objectives and performance of the Company and its
subsidiaries and constitute forward-looking statements made pursuant to the
Safe Harbor provision of the Private Securities Litigation Reform Act of 1995.
Except as otherwise disclosed, the Company's forward-looking statements do not
reflect the impact of possible or pending acquisitions, divestitures or
restructurings. The Company cannot guarantee the absence of errors in input
data, calculations and formulas used in its estimates, assumptions and
forecasts. The Company undertakes no obligation to correct or update any
forward-looking statements whether as a result of new information, future
events or otherwise.
All statements based on future expectations rather than on historical facts are
forward-looking statements that are dependent on certain events, risks and
uncertainties that could cause actual results to differ materially from those
anticipated. Some of these include, but are not limited to, economic and
competitive conditions, inflation rates, legislative and regulatory changes,
financial market conditions, future business decisions, and other
uncertainties, all of which are difficult to predict.
There are numerous uncertainties inherent in estimating quantities of proved
oil and gas reserves and in projecting future rates of production and timing of
development expenditures. The total amount or timing of actual future
production may vary significantly from reserve and production estimates. In the
event Energen Resources Corporation is unable to fully invest its planned
acquisition, development and exploratory expenditures, future operating
revenues, production, and proved reserves could be negatively affected. The
drilling of development and exploratory wells can involve significant risks,
including those related to timing, success rates and cost overruns and these
risks can be affected by lease and rig availability, complex geology and other
factors.
Although Energen Resources makes use of futures, swaps and fixed-price
contracts to mitigate risk, fluctuations in future oil and gas prices could
materially affect the Company's financial position and results of operation;
furthermore, such risk mitigation activities may cause the Company's financial
position and results of operations to be materially different from results that
would have been obtained had such risk mitigation activities not occurred. The
effectiveness of such risk-mitigation assumes that counterparties maintain
satisfactory credit quality.
RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)
26
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," which requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred. The
Company adopted this statement as of January 1, 2002 (See Note 10).
The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or
Disposal Activities" in June 2002. This statement requires that a liability for
costs associated with exit or disposal activities be recognized at fair value
in the period the liability is incurred. This Statement does not apply to costs
associated with the retirement of long-lived assets covered by SFAS No. 143.
The Company has adopted this statement for disposal or exit activities
initiated after December 31, 2002.
The FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure" in December 2002. This statement is effective for
2003 and amends SFAS No. 123, "Accounting for Stock-Based Compensation" by
providing alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation. In
addition, SFAS No. 148 requires additional disclosures related to the effect of
stock-based compensation on reported results. The Company has adopted the
disclosure provisions of SFAS No. 148 and is includedcurrently reviewing its treatment
of stock-based compensation as well as the impact of this pronouncement.
The FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosures
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others," (FIN 45) in Part IV,November 2002. FIN 45 clarifies the requirements of SFAS
No. 5, "Accounting for Contingencies," related to a guarantors accounting for,
and disclosures of, the issuance of certain types of guarantees. Management has
completed a review of potential contingencies and noted the following guarantee
disclosure: Alagasco has an agreement with a financial institution whereby it
can sell on an ongoing basis, with recourse, certain installment receivables
related to its merchandising program up to a maximum of $20 million. Alagasco's
exposure to credit loss in the event of non-performance by customers is
represented by the balance of installment receivables (see Note 8). The Company
is required to adopt the provisions for initial recognition and measurement for
all guarantees issued or modified after December 31, 2002 on a prospective
basis. The Company is currently reviewing the impact related to the initial
recognition and measurement guarantees of this Interpretation.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46) which clarifies the application of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." This
Interpretation provides guidance on the identification and consolidation of
variable interest entities (VIEs), whereby control is achieved through means
other than through voting rights. Management has completed an analysis of FIN
46 and has determined that the Company does not have VIEs.
27
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item in respect to market risk is set forth in
Item 14, Exhibit 13,
herein.
127, Management's Discussion and Analysis of Financial Condition and Results
of Operations under the heading "Outlook" and in Note 8, Financial Instruments
and Risk Management, in the Notes to Financial Statements.
28
14
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item for Energen Corporation and subsidiaries
is incorporated by reference from the 1995 Annual Report to Stockholders and is
included in Part IV, Item 14, Exhibit 13, herein. The information required by
this item for Alabama Gas Corporation is contained in Part IV, Item 14, herein.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the executive officers of both Energen and Alagasco is
included in Part I. The other information required by Item 10 is incorporated
herein by reference from Energen's definitive proxy statement for the Annual
Meeting of Stockholders to be held January 24, 1996. The proxy statement will
be filed within 120 days after the end of the fiscal year covered by this Form
10-K. The directors and nominees for director of Alagasco are the same as
those of Energen except the Alagasco directors do not have staggered terms,
thus the entire Alagasco Board has been nominated for re-election to an annual
term at the Annual Meeting.
ITEM 11. EXECUTIVE COMPENSATION
The information regarding executive compensation is incorporated herein by
reference from Energen's definitive proxy statement for the Annual Meeting of
Stockholders to be held January 24, 1996.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
A. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The information regarding the security ownership of the beneficial owners
of more than five percent of Energen's common stock is incorporated herein
by reference from Energen's definitive proxy statement for the Annual
Meeting of Stockholders to be held January 24, 1996.
B. SECURITY OWNERSHIP OF MANAGEMENT
The information regarding the security ownership of management is
incorporated herein by reference from Energen's definitive proxy statement
for the Annual Meeting of Stockholders to be held January 24, 1996.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related transactions is
incorporated herein by reference from Energen's definitive proxy statement for
the Annual Meeting of Stockholders to be held January 24, 1996.
13
15
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
a. DOCUMENTS FILED AS PART OF THIS REPORT
(1) FINANCIAL STATEMENTS
The financial statements listed in the accompanying Index to
Financial Statements and Financial Statement Schedules are filed as
part of this report and are included in Part IV, Item 14, Exhibit 13,
herein.
(2) FINANCIAL STATEMENT SCHEDULES
The financial statement schedules listed in the accompanying Index to
Financial Statements and Financial Statement Schedules are filed as
part of this report.
(3) EXHIBITS
The exhibits listed on the accompanying Index to Exhibits are filed
as part of this report.
b. REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the fourth quarter of 1995.
14
16
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrants have duly caused this report to be signed
on their behalf by the undersigned thereunto duly authorized.
ENERGEN CORPORATION
(Registrant)
ALABAMA GAS CORPORATION
(Registrant)
December 20, 1995 /s/Rex J. Lysinger
- ------------------------- -------------------------------------------------
DATE Rex J. Lysinger
Chairman of the Board of Directors of Energen
and all subsidiaries, Chief Executive Officer of
Energen
15
17
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed by the following persons on behalf of the Registrants
and in the capacities and on the dates indicated:
December 20, 1995 /s/Rex J. Lysinger
- -------------------------- -----------------------------------------------------------
DATE Rex J. Lysinger
Chairman of the Board of Directors of Energen and all
subsidiaries, Chief Executive Officer of Energen
December 20, 1995 /s/Wm. Michael Warren, Jr.
- -------------------------- -----------------------------------------------------------
DATE Wm. Michael Warren, Jr.
President and Director of Energen and all
subsidiaries, Chief Executive Officer of Alagasco and Chief
Operating Officer of Energen
December 20, 1995 /s/Geoffrey C. Ketcham
- -------------------------- -----------------------------------------------------------
DATE Geoffrey C. Ketcham
Executive Vice President, Chief
Financial Officer and Treasurer
December 20, 1995 /s/Paula H. Rushing
- -------------------------- -----------------------------------------------------------
DATE Paula H. Rushing
Controller of Alagasco
December 20, 1995 /s/Stephen D. Ban
- -------------------------- -----------------------------------------------------------
DATE Stephen D. Ban
Director
December 20, 1995 /s/James S. M. French
- -------------------------- -----------------------------------------------------------
DATE James S. M. French
Director
December 20, 1995 /s/Harris Saunders, Jr.
- -------------------------- -----------------------------------------------------------
DATE Harris Saunders, Jr.
Director
December 20, 1995 /s/Judy M. Merritt
- -------------------------- -----------------------------------------------------------
DATE Judy M. Merritt
Director
16
18
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
ITEM 14(a)
Reference Page
--------------
1995
1995 Annual
10-K Report
---- ------
1. Energen Corporation
-------------------
A. Financial Statements
ENERGEN CORPORATION
Report of Independent Certified Public Accountants . . . . . . . . . 55Accountants................................................................................. 31
Consolidated statementsStatements of incomeIncome for the year ended December 31, 2002, the
three months ended December 31, 2001, and the years ended September 30,
1995, 19942001 and 1993 . . . . . . . . . . . . . . . . . 352000.................................................................................................... 32
Consolidated balance sheetsBalance Sheets as of December 31, 2002 and 2001, and
September 30, 19952001............................................................................................... 33
Consolidated Statements of Shareholders' Equity for the year ended December
31, 2002, the three months ended December 31, 2001, and 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Consolidated statements of shareholders' equity for the years ended
September 30, 1995, 19942001 and 1993 . . . . . . . . . . . . . . 382000...................................................................................... 35
Consolidated statementsStatements of cash flowsCash Flows for the year ended December 31,
2002, the three months ended December 31, 2001, and the years ended
September 30, 1995, 19942001 and 1993 . . . . . . . . . . . . . . . . . 392000...................................................................................... 36
Notes to consolidated financial statements . . . . . . . . . . . . . 40
B. Financial Statement SchedulesStatements.................................................................................... 42
ALABAMA GAS CORPORATION
Report of Independent Certified Public Accountants . . . . . . . . . 39
Schedule II Valuation and Qualifying Accounts . . . . . . . . . 40
2. Alabama Gas Corporation
-----------------------
A. Financial Statements
Report of Independent Certified Public Accounts . . . . . . . . . . 22Accountants................................................................................ 31
Statements of incomeIncome for the year ended December 31, 2002, the three months
ended December 31, 2001, and the years ended September 30, 1995, 19942001 and 1993 . . . . . . . . . . . . . . . . . 232000......................................... 37
Balance sheetsSheets as of December 31, 2002 and 2001, and September 30, 1995 and 1994 . . . . . . . . . . 24
17
19
Reference Page
--------------
1995
1995 Annual
10-K Report
---- ------
2001 ......................................... 38
Statements of shareholder's equityShareholder's Equity for the year ended December 31, 2002, the
three months ended December 31, 2001, and the years ended September 30,
1995, 19942001 and 1993 . . . . . . . . . . . . . . . . . 262000.................................................................................................... 40
Statements of cash flowsCash Flows for the year ended December 31, 2002, the three
months ended December 31, 2001, and the years ended September 30, 1995, 19942001
and 1993 . . . . . . . . . . . . . . . . . 272000......................................................................................................... 41
Notes to financial statements . . . . . . . . . . . . . . . . . . . 28
B.Financial Statements.................................................................................... 42
2. Financial Statement Schedules
ENERGEN CORPORATION
Schedule II - Valuation and Qualifying Accounts . . . . . . . . . 41Accounts.................................................................. 73
ALABAMA GAS CORPORATION
Schedule II - Valuation and Qualifying Accounts.................................................................. 73
Schedules other than those listed above are omitted for the reason thatbecause they are not
required or are not applicable, or the required information is shown in the
financial statements or notes thereto.
1829
20
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO EXHIBITS
ITEM 14(A)(3)
Exhibit
Number Description
- ------- -----------
*3(a) Restated Certificate of Incorporation of Energen Corporation (formerly Alagasco, Inc.) which was filed as
Exhibit 4(a) to Energen's Registration Statement on Form S-8 (Registration No. 33-14855).
*3(b) Amendment to the Restated Certificate of Incorporation of Energen Corporation (formerly Alagasco, Inc.)
adopted on July 18, 1985, which was filed as Exhibit 4(b) to Energen's Registration Statement on Form S-8
(Registration No. 33-14855).
*3(c) Amendment to the Restated Certificate of Incorporation of Energen Corporation adopted on January 15, 1987,
which was filed as Exhibit 4(c) to Energen's Registration Statement on Form S-8 (Registration No.
33-14855).
*3(d) Amendment to the Restated Certificate of Incorporation of Energen Corporation adopted on January 25, 1989,
which was filed as Exhibit 4(d) to Energen's Registration Statement on Form S-3 (Registration No.
33-70464).
3(e) Articles of Amendment to the Restated Certificate of Incorporation of Energen Corporation dated February
3, 1995.
3(f) Restated Conformed Certificate of Incorporation of Energen Corporation, as amended through February 3,
1995.
*3(g) Certificate of Adoption of Resolutions designating Series A Junior Participating Preferred Stock (June 27,
1988) which was filed as Exhibit 4(e) to Energen's Registration Statement on Form S-2 (Registration No.
33-25435).
*3(h) Bylaws of Energen Corporation, which were filed as Exhibit 4(e) to Energen's Registration Statement on
Form S-8 (Registration No. 33-14855).
3(i) Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated
September 27, 1995.
*3(j) By-Laws of Alabama Gas Corporation, which was filed as Exhibit 4(k) to Alabama Gas' Registration Statement
on Form S-3 (Registration No. 33-12841).
*4(a) Rights Agreement, dated as of July 27, 1988, between Energen Corporation and AmSouth Bank, N.A., Rights
Agent, which was filed as Exhibit 1 to Energen's Registration Statement on Form 8-A (File No. 1-7810).
*4(b) Amendment of Rights Agreement, dated as of February 28, 1990, between Energen Corporation and AmSouth
Bank, N.A., Rights Agent, which was filed as Exhibit 2 to Energen's Form 8 Amendment No. 2 to its
Registration Statement on Form 8-A (File No. 1-7810).
19
21
*4(c) Indenture, dated as of January 1, 1992, between Energen Corporation and Boatmen's Trust Company, Trustee,
which was filed as Exhibit 4 to Energen's Amendment No. 1 to Registration Statement on Form S-3
(Registration No. 33-44936).
*4(d) Indenture, dated as of March 1, 1993, between Energen Corporation and Boatmen's Trust Company, Trustee,
which was filed as Exhibit 4 to Energen's Registration Statement on Form S-3 (Registration No.
33-25435).
*4(e) Indenture dated as of November 1, 1993, between Alabama Gas Corporation and NationsBank of Georgia,
National Association, Trustee, which was filed as Exhibit 4(k) to Alabama Gas's Registration Statement on
Form S-3 (Registration No. 33-70466).
*10(a) Form of Service Agreement Under Rate Schedule CSS (No. S10710), between Southern Natural Gas Company and
Alabama Gas Corporation as filed as Exhibit 10(a) to Energen's Annual Report on Form 10-K for the year
ended September 30, 1993.
*10(b) Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and
Alabama Gas Corporation as filed as Exhibit 10(b) to Energen's Annual Report on Form 10-K for the year
ended September 30, 1993.
*10(c) Form of Service Agreement Under Rate Schedule FT-NN (No. 866941), between Southern Natural Gas Company and
Alabama Gas Corporation as filed as Exhibit 10(c) to Energen's Annual Report on Form 10-K for the year
ended September 30, 1993.
*10(d) Form of Service Agreement Under Rate Schedule FT (No. 866940) between Southern Natural Gas Company and
Alabama Gas Corporation as filed as Exhibit 10(d) to Energen's Annual Report on Form 10-K for the year
ended September 30, 1993.
*10(e) Form of Executive Retirement Supplement Agreement between Energen Corporation and certain executive
officers as filed as Exhibit 10(f) to Energen's Annual Report on Form 10-K for the year ended September
30, 1993.
*10(f) Amendment to Executive Retirement Supplement Agreement effective as of June 22, 1994, between Energen
Corporation and certain executive officers as filed as Exhibit 10(f) to Energen's Annual Report on Form
10-K for the year ended September 30, 1994.
*10(g) Restricted Stock Incentive Plan of Energen Corporation, which was filed as Exhibit 4 to Post Effective
Amendment No. 2 to Energen Corporation's Registration Statement on Forms S-8 and S-3 (Registration No.
2-89855).
*10(h) Severance Compensation Agreement between Energen Corporation and certain executive officers, which was
filed as Exhibit 10(e) to Energen's Annual Report on Form 10-K for the year ended September 30, 1992.
*10(i) Energen Corporation 1988 Stock Option Plan as filed as Exhibit 10(i) to Energen's Annual Report on Form
10-K for the year ended September 30, 1993.
*10(j) Energen Corporation 1992 Long-Range Performance Share Plan, dated as of October 1, 1991, which was filed
as Exhibit A to the Registrant's Proxy Statement for its January 22, 1992, Annual Meeting (File No.
1-7810).
20
22
*10(k) Energen Corporation 1992 Directors Stock Plan, effective as of January 22, 1992, which was filed as
Exhibit B to Energen's Proxy Statement for its January 22, 1992, Annual Meeting (File No. 1-7810).
*10(l) Energen Corporation Director Fees Deferral Plan as filed as Exhibit 10(l) to Energen's Annual Report on
Form 10-K for the year ended September 30, 1993.
*10(m) Energen Corporation Annual Incentive Compensation Plan, Revised 5/90, as amended effective October 1,
1993, as filed as Exhibit 10(m) to Energen's Annual report on Form 10-K for the year ended September 30,
1994.
13 Information incorporated by reference from pages 25-59 of the Energen Corporation 1995 Annual Report to
Stockholders
21 Subsidiaries of Energen Corporation
23(a) Consent of Independent Certified Public Accountants (Energen)
23(b) Consent of Independent Certified Public Accountants (Alagasco)
27.1 Financial Data Schedule of Alabama Gas Corporation (for SEC purposes only)
27.2 Financial Data Schedule of Energen Corporation (for SEC purposes only)
*Incorporated by reference
21
23
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS OF ALABAMA GAS CORPORATION:
We have auditedMANAGEMENT
The accompanying consolidated financial statements and related notes of Energen
Corporation and subsidiaries and the financial statements and the financial statement schedulesrelated notes of
Alabama Gas Corporation (collectively, "the financial statements") were
prepared by management, which has the primary responsibility for the integrity
of the financial information therein. These financial statements were prepared
in conformity with accounting principles generally accepted in the United
States of America appropriate in the circumstances and include amounts which
are based necessarily on management's best estimates and judgments. Financial
information presented elsewhere in this report is consistent with the
information in the financial statements.
Management maintains a comprehensive system of internal accounting controls and
relies on the system to discharge its responsibility for the integrity of the
financial statements. This system provides reasonable assurance that corporate
assets are safeguarded and that transactions are recorded in such a manner as
to permit the preparation of materially reliable financial information.
Reasonable assurance recognizes that the cost of a system of internal
accounting controls should not exceed the related benefits. This system of
internal accounting controls is augmented by written policies and procedures,
internal auditing, and the careful selection and training of qualified
personnel. As of December 31, 2002, management was aware of no material
weaknesses in Energen or Alabama Gas Corporation's systems of internal
accounting controls.
The financial statements have been audited by the Company's independent
accountants, whose opinions are expressed elsewhere in this Form 10-K. Their
audits were conducted in accordance with generally accepted auditing standards;
and, in connection therewith, they obtained an understanding of the Company's
systems of internal accounting controls and conducted such tests and related
procedures as they deemed necessary to arrive at an opinion on the fairness of
presentation of the financial statements.
The functioning of the accounting system and related internal accounting
controls is under the general oversight of the Audit Committee of the Board of
Directors, which is comprised of four outside Directors. The Audit Committee
meets regularly with the independent accountants and representatives of
management to discuss matters regarding internal accounting controls, auditing
and financial reporting.
Geoffrey C. Ketcham
Executive Vice President,
Chief Financial Officer and Treasurer
30
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE SHAREHOLDERS OF ENERGEN CORPORATION:
In our opinion, the consolidated financial statements of Energen Corporation
listed in the accompanying index on pages 17present fairly, in all material respects, the
financial position of Energen Corporation and 18subsidiaries at December 31, 2002
and 2001 and September 30, 2001, and the results of this Form
10-K.their operations and their
cash flows for the year ended December 31, 2002, the three months ended
December 31, 2001 and the years ended September 30, 2001 and 2000, in
conformity with accounting principles generally accepted in the United States
of America. In addition, in our opinion, the financial statement schedule
listed in the accompanying index presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements. These financial statements and financial
statement schedulesschedule are the responsibility of the Company's management. Ourmanagement; our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our audits of
these statements in accordance with auditing standards generally accepted auditing
standards. Those standardsin
the United States of America, which require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit
also includesstatements,
assessing the accounting principles used and significant estimates made by
management, as well asand evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
As discussed in Notes 10 and 12, of the Notes to Financial Statements,
effective January 1, 2002, the Company adopted Statement of Financial
Accounting Standard (SFAS) No. 143, "Accounting for Asset Retirement
Obligations" and SFAS No. 144, "Accounting for the Impairment of Long-Lived
Assets," respectively.
PricewaterhouseCoopers LLP
Birmingham, Alabama
February 21, 2003
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF ALABAMA GAS CORPORATION:
In our opinion, the financial statements referred to aboveof Alabama Gas Corporation listed in
the accompanying index present fairly, in all material respects, the financial
position of Alabama Gas Corporation as ofat December 31, 2002 and 2001 and September
30, 1995 and 1994,2001, and the results of its operations and its cash flows for each ofthe year
ended December 31, 2002, the three years inmonths ended December 31, 2001 and the periodyears
ended September 30, 1995,2001 and 2000, in conformity with accounting principles
generally accepted accounting principles.in the United States of America. In addition, in our
opinion, the financial statement schedules referred to above, when consideredschedule listed in relation to the basic financial statements taken as a whole, presentaccompanying index
presents fairly, in all material respects, the information requiredset forth therein
when read in conjunction with the related financial statements. These financial
statements and financial statement schedule are the responsibility of the
Company's management; our responsibility is to be included therein.
As discussedexpress an opinion on these
financial statements and financial statement schedule based on our audits. We
conducted our audits of these statements in Note 6accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the Company changed its
method ofamounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for certain other post-retirement benefits, effective
October 1, 1993.
Coopers & Lybrand L.L.P.our opinion.
PricewaterhouseCoopers LLP
Birmingham, Alabama
October 25, 1995
22February 21, 2003
31
24CONSOLIDATED STATEMENTS OF INCOME
ALABAMA GASENERGEN CORPORATION
===========================================================================================================
YEARSThree Months
YEAR ENDED SEPTEMBEREnded Year Ended Year Ended
DECEMBER 31, December 31, September 30, (IN THOUSANDS) 1995 1994 1993
===========================================================================================================September 30,
(in thousands, except share data) 2002 2001 2001 2000
------------ ------------ ------------- -------------
OPERATING REVENUES
$295,967 $344,637 $330,560
- -----------------------------------------------------------------------------------------------------------Oil and gas operations $ 252,744 $ 49,486 $ 223,512 $ 185,248
Natural gas distribution 424,431 96,678 553,862 366,161
----------- ----------- ----------- -----------
Total operating revenues 677,175 146,164 777,374 551,409
----------- ----------- ----------- -----------
OPERATING EXPENSES
Cost of gas 133,556 188,592 187,800189,810 45,291 327,531 154,201
Operations 78,139 72,639 66,196
Maintenance 9,727 9,147 8,781and maintenance 195,954 54,630 182,295 170,708
Depreciation, 19,370 17,941 17,206
Income taxes
Current 8,392 10,623 5,407
Deferred, net 177 (2,418) 1,530
Deferred investment tax credits, net (487) (487) (528)depletion and amortization 105,087 24,502 84,779 84,934
Taxes, other than income taxes 22,662 26,301 24,196
- -----------------------------------------------------------------------------------------------------------50,238 10,881 61,734 46,555
----------- ----------- ----------- -----------
Total operating expenses 271,536 322,338 310,588
- -----------------------------------------------------------------------------------------------------------541,089 135,304 656,339 456,398
----------- ----------- ----------- -----------
OPERATING INCOME 24,431 22,299 19,972
- -----------------------------------------------------------------------------------------------------------136,086 10,860 121,035 95,011
----------- ----------- ----------- -----------
OTHER INCOME Allowance for funds used during construction 1,054 465 163(EXPENSE)
Interest expense (43,713) (10,634) (42,070) (37,769)
Accretion expense (1,819) -- -- --
Other net (112) 452 376
- -----------------------------------------------------------------------------------------------------------income 15,644 4,354 16,825 17,315
Other expense (15,103) (4,385) (14,892) (15,540)
----------- ----------- ----------- -----------
Total other income 942 917 539
- -----------------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interestexpense (44,991) (10,665) (40,137) (35,994)
----------- ----------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME
TAXES AND CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 91,095 195 80,898 59,017
Income tax expense (benefit) 20,509 (3,384) 14,811 6,482
----------- ----------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 70,586 3,579 66,087 52,535
----------- ----------- ----------- -----------
DISCONTINUED OPERATIONS, NET OF TAXES
Income (loss) from discontinued operations (267) 79 1,809 483
Gain on long-term debt 7,730 6,475 5,532
Other interest expense 1,922 1,845 1,955
- -----------------------------------------------------------------------------------------------------------
Total interest charges 9,652 8,320 7,487
- -----------------------------------------------------------------------------------------------------------disposal 540 -- -- --
----------- ----------- ----------- -----------
INCOME FROM DISCONTINUED OPERATIONS 273 79 1,809 483
----------- ----------- ----------- -----------
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF TAXES (2,220) -- -- --
----------- ----------- ----------- -----------
NET INCOME 15,721 14,896 13,024
Less cash dividends on cumulative preferred stock$ 68,639 $ 3,658 $ 67,896 $ 53,018
=========== =========== =========== ===========
DILUTED EARNINGS PER AVERAGE COMMON SHARE
Continuing operations $ 2.09 $ 0.12 $ 2.13 $ 1.73
Discontinued operations 0.01 -- 0.05 0.02
Cumulative effect of change in accounting principle (0.07) -- -- 70
- -----------------------------------------------------------------------------------------------------------
NET INCOME AVAILABLE FOR--
----------- ----------- ----------- -----------
Net Income $ 2.03 $ 0.12 $ 2.18 $ 1.75
=========== =========== =========== ===========
BASIC EARNINGS PER AVERAGE COMMON SHARE
Continuing operations $ 15,7212.10 $ 14,8960.12 $ 12,954
===========================================================================================================2.15 $ 1.74
Discontinued operations 0.01 -- 0.06 0.02
Cumulative effect of change in accounting principle (0.07) -- -- --
----------- ----------- ----------- -----------
Net Income $ 2.04 $ 0.12 $ 2.21 $ 1.76
=========== =========== =========== ===========
DILUTED AVERAGE COMMON SHARES OUTSTANDING 33,838,299 31,277,406 31,083,784 30,359,417
=========== =========== =========== ===========
BASIC AVERAGE COMMON SHARES OUTSTANDING 33,604,601 31,052,152 30,725,919 30,108,149
=========== =========== =========== ===========
The accompanying Notes to Financial Statements are an integral part of these
statements.
2332
25CONSOLIDATED BALANCE SHEETS
ALABAMA GASENERGEN CORPORATION
===========================================================================================================
YEARS ENDED SEPTEMBERDECEMBER 31, December 31, September 30,
(IN THOUSANDS) 1995 1994
===========================================================================================================(in thousands) 2002 2001 2001
------------ ------------ -------------
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant $504,371 $464,593
Less accumulated depreciation 247,926 231,327
- -----------------------------------------------------------------------------------------------------------
Utility plant, net 256,445 233,266
- -----------------------------------------------------------------------------------------------------------
Other property, net 193 183
- -----------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash 727 156and cash equivalents $ 4,804 $ 6,482 $ 5,333
Accounts receivable, Gas 22,215 22,209
Merchandise 1,546 1,326
Other 1,598 1,512
Allowancenet of allowance for doubtful accounts
(2,000) (2,000)of $8,874 at December 31, 2002, of $11,783 at December
31, 2001, and of $10,031 at September 30, 2001 100,946 77,106 74,078
Inventories, at average cost
Storage gas inventory 20,276 24,36323,668 50,978 56,761
Materials and supplies 5,860 5,6888,335 8,894 10,225
Liquified natural gas in storage 3,539 3,3493,671 3,146 3,271
Deferred gas costs 1,426 1,46021,040 17,776 3,275
Regulatory asset 6,321 -- -- 95
Deferred income taxes 7,416 5,72433,941 29,636 12,425
Prepayments and other 2,302 2,595
- -----------------------------------------------------------------------------------------------------------20,367 6,948 27,081
---------- ---------- ----------
Total current assets 71,226 66,382
- -----------------------------------------------------------------------------------------------------------
DEFERRED CHARGES216,772 200,966 192,544
---------- ---------- ----------
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, successful efforts method 1,103,472 844,962 822,956
Less accumulated depreciation, depletion and amortization 269,616 228,867 209,451
---------- ---------- ----------
Oil and gas properties, net 833,856 616,095 613,505
---------- ---------- ----------
Utility plant 825,421 769,259 758,374
Less accumulated depreciation 408,165 384,430 378,218
---------- ---------- ----------
Utility plant, net 417,256 384,829 380,156
---------- ---------- ----------
Other property, net 5,691 4,755 4,673
---------- ---------- ----------
Total property, plant and equipment, net 1,256,803 1,005,679 998,334
---------- ---------- ----------
OTHER ASSETS
7,403 9,074
- -----------------------------------------------------------------------------------------------------------Deferred income taxes 16,333 8,406 12,039
Regulatory asset 14,744 -- --
Deferred charges and other 26,239 25,305 20,962
---------- ---------- ----------
Total other assets 57,316 33,711 33,001
---------- ---------- ----------
TOTAL ASSETS $335,267 $308,905
===========================================================================================================$1,530,891 $1,240,356 $1,223,879
========== ========== ==========
The accompanying Notes to Financial Statements are an integral part of these
statements.
2433
26CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
DECEMBER 31, December 31, September 30,
(in thousands, except share data) 2002 2001 2001
------------ ------------ -------------
CAPITAL AND LIABILITIES
CURRENT LIABILITIES
Long-term debt due within one year $ 23,000 $ 16,072 $ 16,072
Notes payable to banks 113,000 24,000 7,000
Accounts payable 103,964 58,783 65,412
Accrued taxes 27,936 32,183 30,014
Customers' deposits 17,404 16,399 15,195
Amounts due customers 8,458 6,434 --
Accrued wages and benefits 23,652 22,711 25,821
Regulatory liability 23,814 8,462 3,792
Other 34,710 29,564 32,217
---------- ---------- ----------
Total current liabilities 375,938 214,608 195,523
---------- ---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES
Asset retirement obligation 27,235 -- --
Minimum pension liability 25,825 -- --
Regulatory liability 1,468 137 242
Other 4,661 7,273 3,237
---------- ---------- ----------
Total deferred credits and other liabilities 59,189 7,410 3,479
---------- ---------- ----------
COMMITMENTS AND CONTINGENCIES
CAPITALIZATION
Preferred stock, cumulative, $0.01 par value, 5,000,000
shares authorized -- -- --
Common shareholders' equity
Common stock, $0.01 par value; 75,000,000 shares
authorized, 34,745,477 shares outstanding at December 31,
2002, 31,248,547 shares outstanding at December 31, 2001,
and 31,124,761 shares outstanding at September 30, 2001 347 312 311
Premium on capital stock 320,060 235,976 233,471
Capital surplus 2,802 2,802 2,802
Retained earnings 275,266 230,554 232,354
Accumulated other comprehensive income (loss), net of tax
Unrealized gain (loss) on hedges (10,471) 7,168 15,531
Minimum pension liability (4,340) -- --
Deferred compensation on restricted stock (770) (1,513) (1,186)
Deferred compensation plan 10,348 7,222 5,259
Treasury stock, at cost; 358,228 shares and 341,465 shares at
December 31, 2002 and 2001, respectively, and 325,355
shares at September 30, 2001 (10,432) (8,316) (7,775)
---------- ---------- ----------
Total common shareholders' equity 582,810 474,205 480,767
Long-term debt 512,954 544,133 544,110
---------- ---------- ----------
Total capitalization 1,095,764 1,018,338 1,024,877
---------- ---------- ----------
TOTAL CAPITAL AND LIABILITIES $1,530,891 $1,240,356 $1,223,879
========== ========== ==========
The accompanying Notes to Financial Statements are an integral part of these
statements.
34
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
ENERGEN CORPORATION
(in thousands, except share amounts)
Common Stock
--------------------------
Number of Par Premium on Capital Retained
Shares Value Capital Stock Surplus Earnings
---------- ---------- ------------- ---------- ----------
BALANCE SEPTEMBER 30, 1999 29,903,964 $ 299 $ 205,831 $ 2,802 $ 152,572
Net income 53,018
Purchase of treasury shares
Shares issued for:
Dividend reinvestment plan 57,920 1 1,438
Employee benefit plans 388,918 4 6,313
Deferred compensation obligation
Cash dividends - $0.665 per share (20,029)
---------- ---------- ---------- ---------- ----------
BALANCE SEPTEMBER 30, 2000 30,350,802 304 213,582 2,802 185,561
Net income 67,896
Other comprehensive income (loss):
Transition adjustment on cash
flow hedging activities, net of
tax of ($35,430)
Current period change in fair value
of derivative instruments, net of
tax of $11,740
Reclassification adjustment, net of
tax of $33,619
Comprehensive income
Purchase of treasury shares
Shares issued for:
Dividend reinvestment plan 75,480 1 2,366
Employee benefit plans 698,479 6 17,523
Deferred compensation obligation
Issuance of restricted stock
Amortization of restricted stock
Cash dividends - $0.685 per share (21,103)
---------- ---------- ---------- ---------- ----------
BALANCE SEPTEMBER 30, 2001 31,124,761 311 233,471 2,802 232,354
Net income 3,658
Other comprehensive loss:
Current period change in fair value
of derivative instruments, net of
tax of ($187)
Reclassification adjustment, net of
tax of ($3,821)
Minimum pension liability, net of
tax of ($1,127)
Comprehensive loss
Purchase of treasury shares
Shares issued for:
Dividend reinvestment plan 5,519 -- 72
Employee benefit plans 118,267 1 2,433
Deferred compensation obligation
Issuance of restricted stock
Amortization of restricted stock
Cash dividends - $0.175 per share (5,458)
---------- ---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 2001 31,248,547 312 235,976 2,802 230,554
Net income 68,639
Other comprehensive loss:
Current period change in fair value
of derivative instruments, net of
tax of ($9,893)
Reclassification adjustment, net of
tax of ($2,724)
Minimum pension liability, net of
tax of ($1,211)
Comprehensive loss
Purchase of treasury shares
Shares issued for:
Stock issuance for acquisition 3,043,479 30 72,861
Dividend reinvestment plan 77,725 1 2,020
Employee benefit plans 375,726 4 9,203
Deferred compensation obligation
Amortization of restricted stock
Cash dividends - $0.71 per share (23,927)
---------- ---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 2002 34,745,477 $ 347 $ 320,060 $ 2,802 $ 275,266
========== ========== ========== ========== ==========
(in thousands, except share amounts)
Accumulated
Other Deferred Deferred
Comprehensive Compensation Compensation Treasury Shareholders'
Income (Loss) Restricted Stock Plan Stock Equity
------------- ---------------- ------------ ---------- -------------
BALANCE SEPTEMBER 30, 1999 $ -- $ -- $ 2,054 $ (2,054) $ 361,504
Net income 53,018
Purchase of treasury shares (4,934) (4,934)
Shares issued for:
Dividend reinvestment plan 1,395 2,834
Employee benefit plans 2,150 8,467
Deferred compensation obligation 2,911 (2,911) --
Cash dividends - $0.665 per share (20,029)
---------- ---------- ---------- ---------- ----------
BALANCE SEPTEMBER 30, 2000 -- -- 4,965 (6,354) 400,860
Net income 67,896
Other comprehensive income (loss):
Transition adjustment on cash
flow hedging activities, net of
tax of ($35,430) (55,416) (55,416)
Current period change in fair Value
of derivative instruments, net of
tax of $11,740 18,363 18,363
Reclassification adjustment, net of
tax of $33,619 52,584 52,584
----------
Comprehensive income 83,427
----------
Purchase of treasury shares (2,516) (2,516)
Shares issued for:
Dividend reinvestment plan 331 2,698
Employee benefit plans 1,058 18,587
Deferred compensation obligation 294 (294) --
Issuance of restricted stock (1,662) (1,662)
Amortization of restricted stock 476 476
Cash dividends - $0.685 per share (21,103)
---------- ---------- ---------- ---------- ----------
BALANCE SEPTEMBER 30, 2001 15,531 (1,186) 5,259 (7,775) 480,767
Net income 3,658
Other comprehensive loss:
Current period change in fair value
of derivative instruments, net of
tax of ($187) (292) (292)
Reclassification adjustment, net of
tax of ($3,821) (5,977) (5,977)
Minimum pension liability, net of
tax of ($1,127) (2,094) (2,094)
----------
Comprehensive loss (4,705)
----------
Purchase of treasury shares (1,245) (1,245)
Shares issued for:
Dividend reinvestment plan 689 761
Employee benefit plans 1,978 4,412
Deferred compensation obligation 1,963 (1,963) --
Issuance of restricted stock (515) (515)
Amortization of restricted stock 188 188
Cash dividends - $0.175 per share (5,458)
---------- ---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 2001 7,168 (1,513) 7,222 (8,316) 474,205
Net income 68,639
Other comprehensive loss:
Current period change in fair value
of derivative instruments, net of
tax of ($9,893) (15,473) (15,473)
Reclassification adjustment, net of
tax of ($2,724) (4,260) (4,260)
Minimum pension liability, net of
tax of ($1,211) (2,246) (2,246)
----------
Comprehensive loss 46,660
----------
Purchase of treasury shares (133) (133)
Shares issued for:
Stock issuance for acquisition 72,891
Dividend reinvestment plan 401 2,422
Employee benefit plans 742 9,949
Deferred compensation obligation 3,126 (3,126) --
Amortization of restricted stock 743 743
Cash dividends - $0.71 per share (23,927)
---------- ---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 2002 $ (14,811) $ (770) $ 10,348 $ (10,432) $ 582,810
========== ========== ========== ========== ==========
The accompanying Notes to Financial Statements are an integral part of these
statements.
35
CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------- ------------- -------------
OPERATING ACTIVITIES
Net income $ 68,639 $ 3,658 $ 67,896 $ 53,018
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization 110,767 25,184 86,975 87,073
Deferred income taxes, net 10,915 (8,495) 5,349 (5,400)
Deferred investment tax credits, net (448) (112) (448) (448)
Change in derivative fair value (9,205) (174) (879) --
(Gain) loss on sale of assets (3,738) 3,161 (4,716) (1,107)
Loss on properties held for sale -- -- 3,821 --
Cumulative effect of change in accounting
principle, net of taxes (2,220) -- -- --
Net change in:
Accounts receivable (23,840) (3,028) 19,284 (18,857)
Inventories 27,344 7,239 (22,018) (11,912)
Accounts payable 28,600 2,442 16,544 4,569
Deferred gas costs (3,264) (14,501) 281 (1,251)
Amounts due customers 626 11,637 (11,655) (3,662)
Other current assets and liabilities 1,712 (4,813) 1,424 8,370
Other, net 7,619 (837) (5,362) (5,350)
--------- -------- --------- ---------
Net cash provided by operating activities 213,507 21,361 156,496 105,043
--------- -------- --------- ---------
INVESTING ACTIVITIES
Additions to property, plant and equipment (166,075) (37,752) (190,695) (133,061)
Acquisition, net of cash acquired (117,043) -- -- --
Proceeds from sale of assets 17,094 2,323 17,326 2,647
Other, net (2,198) (252) (1,038) (1,329)
--------- -------- --------- ---------
Net cash used in investing activities (268,222) (35,681) (174,407) (131,743)
--------- -------- --------- ---------
FINANCING ACTIVITIES
Payment of dividends on common stock (23,927) (5,458) (21,103) (20,029)
Issuance of common stock 12,371 5,172 21,285 11,301
Purchase of treasury stock (133) (1,245) (2,516) (4,934)
Reduction of long-term debt (21,204) -- (36,267) (1,205)
Proceeds from issuance of long-term debt -- -- 223,799 --
Debt issuance costs -- -- (4,777) --
Net change in short-term debt issued to purchase
U.S. Treasury securities -- -- -- (140,917)
Net change in short-term debt 85,930 17,000 (161,000) 40,917
--------- -------- --------- ---------
Net cash provided by (used in) financing activities 53,037 15,469 19,421 (114,867)
--------- -------- --------- ---------
Net change in cash and cash equivalents (1,678) 1,149 1,510 (141,567)
Cash and cash equivalents at beginning of period 6,482 5,333 3,823 145,390
--------- -------- --------- ---------
Cash and cash equivalents at end of period $ 4,804 $ 6,482 $ 5,333 $ 3,823
========= ======== ========= =========
The accompanying Notes to Financial Statements are an integral part of these
statements.
36
STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------- ------------- -------------
OPERATING REVENUES $ 424,431 $ 96,678 $ 553,862 $ 366,161
--------- -------- --------- ---------
OPERATING EXPENSES
Cost of gas 191,479 45,651 329,572 155,841
Operations and maintenance 109,115 27,687 105,812 104,206
Depreciation 33,682 8,151 30,933 28,708
Income taxes
Current 8,764 10,348 16,995 16,711
Deferred, net 9,509 (8,689) (3,099) (1,939)
Deferred investment tax credits, net (448) (112) (448) (448)
Taxes, other than income taxes 30,785 7,155 37,257 28,343
--------- -------- --------- ---------
Total operating expenses 382,886 90,191 517,022 331,422
--------- -------- --------- ---------
OPERATING INCOME 41,545 6,487 36,840 34,739
--------- -------- --------- ---------
OTHER INCOME (EXPENSE)
Allowance for funds used during construction 1,336 122 2,098 1,172
Other income 5,520 1,596 5,978 7,520
Other expense (6,280) (1,838) (6,585) (7,239)
--------- -------- --------- ---------
Total other income (expense) 576 (120) 1,491 1,453
--------- -------- --------- ---------
INTEREST CHARGES
Interest on long-term debt 13,153 3,327 8,803 8,542
Other interest charges 1,404 353 3,513 1,328
--------- -------- --------- ---------
Total interest charges 14,557 3,680 12,316 9,870
--------- -------- --------- ---------
NET INCOME $ 27,564 $ 2,687 $ 26,015 $ 26,322
========= ======== ========= =========
The accompanying Notes to Financial Statements are an integral part of these
statements.
37
BALANCE SHEETS
ALABAMA GAS CORPORATION
===========================================================================================================
YEARS ENDED SEPTEMBERDecember 31, December 31, September 30,
(IN THOUSANDS) 1995 1994
===========================================================================================================(in thousands) 2002 2001 2001
------------ ------------ -------------
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant $ 825,421 $ 769,259 $ 758,374
Less accumulated depreciation 408,165 384,430 378,218
--------- --------- ---------
Utility plant, net 417,256 384,829 380,156
--------- --------- ---------
Other property, net 842 308 333
--------- --------- ---------
CURRENT ASSETS
Cash 2,818 3,372 1,555
Accounts receivable
Gas 70,220 59,504 47,024
Merchandise 1,748 1,506 1,417
Other 656 626 1,448
Affiliated companies -- -- 937
Allowance for doubtful accounts (8,200) (11,100) (9,500)
Inventories, at average cost
Storage gas inventory 23,668 50,978 56,761
Materials and supplies 5,049 5,363 5,423
Liquified natural gas in storage 3,671 3,146 3,271
Deferred gas costs 21,040 17,776 3,275
Regulatory asset -- -- 95
Deferred income taxes 20,093 22,820 14,477
Prepayments and other 18,314 1,378 2,521
--------- --------- ---------
Total current assets 159,077 155,369 128,704
--------- --------- ---------
OTHER ASSETS
Regulatory asset 14,744 -- --
Deferred charges and other 11,290 8,715 8,546
--------- --------- ---------
Total other assets 26,034 8,715 8,546
--------- --------- ---------
TOTAL ASSETS $ 603,209 $ 549,221 $ 517,739
========= ========= =========
The accompanying Notes to Financial Statements are an integral part of these
statements.
38
BALANCE SHEETS
ALABAMA GAS CORPORATION
DECEMBER 31, December 31, September 30,
(in thousands, except share data) 2002 2001 2001
------------ ------------ -------------
CAPITAL AND LIABILITIES
CAPITALIZATION
Preferred stock, cumulative, $0.01 par value, 120,000
shares authorized $ -- $ -- $ --
Common shareholder's equity
Common stock, $0.01 par value; 3,000,000 shares
authorized, 1,972,052 shares outstanding in 1995at
December 31, 2002 and 1994 $2001, and September 30,
2001, respectively 20 $20 20
Premium on capital stock 31,682 31,682 31,682
Capital Surplussurplus 2,802 2,802 2,802
Retained Earnings 87,638 81,087
- -----------------------------------------------------------------------------------------------------------earnings 182,852 172,147 174,885
-------- -------- --------
Total common shareholder's equity 122,142 115,591
Cumulative preferred stock, $0.01 par value, 120,000 shares
authorized -- --217,356 206,651 209,389
Long-term debt 100,000 84,391
- -----------------------------------------------------------------------------------------------------------169,533 185,000 185,000
-------- -------- --------
Total capitalization 222,142 199,982
- -----------------------------------------------------------------------------------------------------------386,889 391,651 394,389
-------- -------- --------
CURRENT LIABILITIES
Long-term debt due within one year -- 2,82315,000 5,000 5,000
Notes payable to banks -- 4,00013,000 19,000 1,000
Accounts payable
Other 26,160 19,002Trade 55,720 34,023 32,078
Affiliated companies 1,432 3,054 -- 132
Accrued taxes 10,236 14,24124,044 29,505 26,963
Customers' deposits 18,218 17,462
Supplier refunds17,404 16,399 15,195
Amounts due customers 3,315 832
Other amounts due customers 13,231 10,9028,458 6,434 --
Accrued wages and benefits 5,228 5,6595,710 10,509 11,616
Regulatory liability 23,814 8,462 3,792
Other 9,444 7,605
- -----------------------------------------------------------------------------------------------------------8,947 7,289 9,416
-------- -------- --------
Total current liabilities 85,832 82,658
- -----------------------------------------------------------------------------------------------------------173,529 139,675 105,060
-------- -------- --------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 16,343 13,70420,747 15,531 15,825
Minimum pension liability 18,661 -- --
Accumulated deferred investment tax credits 4,103 4,590756 1,204 1,317
Regulatory liability 6,001 6,9601,468 137 242
Customer advances for construction and other 846 1,011
- -----------------------------------------------------------------------------------------------------------1,159 1,023 906
-------- -------- --------
Total deferred credits and other liabilities 27,293 26,265
- -----------------------------------------------------------------------------------------------------------42,791 17,895 18,290
-------- -------- --------
COMMITMENTS AND CONTINGENCIES
-------- -------- --------
TOTAL CAPITAL AND LIABILITIES $335,267 $308,905
===========================================================================================================$603,209 $549,221 $517,739
======== ======== ========
The accompanying Notes to Financial Statements are an integral part of these
statements.
2539
27
STATEMENTS OF SHAREHOLDER'S EQUITY
ALABAMA GAS CORPORATION
============================================================================================================
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
============================================================================================================(in thousands, except share amounts)
COMMON STOCK
---------------------------------------- TOTAL
NUMBER OF PAR PREMIUM ON CAPITAL RETAINED SHAREHOLDER'S
SHARES VALUE CAPITAL STOCK SURPLUS EARNINGS - ------------------------------------------------------------------------------------------------------------EQUITY
--------- --------- ------------- --------- --------- -------------
BALANCE AT SEPTEMBER 30, 19921999 1,972,052 $20 $21,682 $2,802 $69,907$ 20 $ 31,682 $ 2,802 $ 143,502 $ 178,006
Net income 13,02426,322 26,322
Cash dividends -- $1.05 per share (7,975)
Less cash dividends on preferred stock 70
- ------------------------------------------------------------------------------------------------------------(5,057) (5,057)
--------- --------- --------- --------- --------- ---------
BALANCE AT SEPTEMBER 30, 1993 1,972,052 20 21,682 2,802 74,886
Net income 14,896
Cash dividends -- $1.09 per share (8,695)
Capital contribution from parent 10,000
- ------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 19942000 1,972,052 20 31,682 2,802 81,087164,767 199,271
Net income 15,72126,015 26,015
Cash dividends -- $1.13 per share (9,170)
- ------------------------------------------------------------------------------------------------------------(15,897) (15,897)
--------- --------- --------- --------- --------- ---------
BALANCE AT SEPTEMBER 30, 19952001 1,972,052 $20 $31,682 $2,802 $87,638
============================================================================================================20 31,682 2,802 174,885 209,389
Net income 2,687 2,687
Cash dividends (5,425) (5,425)
--------- --------- --------- --------- --------- ---------
BALANCE DECEMBER 31, 2001 1,972,052 20 31,682 2,802 172,147 206,651
Net income 27,564 27,564
Cash dividends (16,859) (16,859)
--------- --------- --------- --------- --------- ---------
BALANCE DECEMBER 31, 2002 1,972,052 $ 20 $ 31,682 $ 2,802 $ 182,852 $ 217,356
========= ========= ========= ========= ========= =========
The accompanying Notes to Financial Statements are an integral part of these
statements.
2640
28
STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
===========================================================================================================
YEARSThree Months
YEAR ENDED SEPTEMBEREnded Year Ended Year Ended
DECEMBER 31, December 31, September 30, (IN THOUSANDS) 1995 1994 1993
===========================================================================================================September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
OPERATING ACTIVITIES
Net Incomeincome $ 15,72127,564 $ 14,8962,687 $ 13,02426,015 $ 26,322
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization 19,370 17,941 17,20633,682 8,151 30,933 28,708
Deferred income taxes, net 177 (2,418) 1,5309,509 (8,689) (3,099) (1,939)
Deferred investment tax credits (487) (487) (528)(448) (112) (448) (448)
Net change in:
Accounts receivable (113) 896 (3,787)(13,887) (10,147) 5,775 (9,290)
Inventories 3,526 (23,913) (94)27,099 5,968 (20,351) (12,040)
Deferred gas costs (3,264) (14,501) 281 (1,251)
Accounts payable 7,026 (890) 3,39821,697 1,945 (7,298) 2,391
Amounts due customers 626 11,637 (11,655) (3,662)
Other current assets and liabilities (3,023) 17,268 968(6,666) 1,191 7,692 1,617
Other, net 673 (2,116) (1,536)
- -----------------------------------------------------------------------------------------------------------(1,447) (201) (2,231) (1,663)
--------- -------- --------- ---------
Net cash provided (used) by operating activities 42,870 21,177 30,181
- -----------------------------------------------------------------------------------------------------------94,465 (2,071) 25,614 28,745
--------- -------- --------- ---------
INVESTING ACTIVITIES
Additions to property, plant and equipment (41,560) (37,853) (21,743)(64,257) (12,820) (53,749) (65,684)
Net advances from (to) from parent company -- 87 (87)(1,622) 3,990 (2,093) 21,811
Other, net (15) 181 (320)
- -----------------------------------------------------------------------------------------------------------(814) 143 (327) 18
--------- -------- --------- ---------
Net cash used in investing activities (41,575) (37,585) (22,150)
- -----------------------------------------------------------------------------------------------------------(66,693) (8,687) (56,169) (43,855)
--------- -------- --------- ---------
FINANCING ACTIVITIES
Payment of dividends on common stock (9,170) (8,695) (7,975)
Payment of dividends on preferred stock -- -- (70)(16,859) (5,425) (15,897) (5,057)
Reduction of long-term debt and preferred stock (37,214) (9,891) (19,500)
Proceeds from medium term notes 49,660 49,670(5,467) -- -- --
Proceeds from capital contribution from parent -- 10,000 --
Net advances to parent companyissuance of long-term debt -- -- (6,299)75,000 --
Debt issuance costs -- -- (3,709) --
Net change in short-term debt (4,000) (25,000) 24,000
Other, net -- -- (101)
- -----------------------------------------------------------------------------------------------------------(6,000) 18,000 (24,150) 20,500
--------- -------- --------- ---------
Net cash (used in) provided (used) by financing activities (724) 16,084 (9,945)
- -----------------------------------------------------------------------------------------------------------(28,326) 12,575 31,244 15,443
--------- -------- --------- ---------
Net change in cash 571 (324) (1,914)and cash equivalents (554) 1,817 689 333
Cash and cash equivalents at beginning of period 156 480 2,394
- -----------------------------------------------------------------------------------------------------------3,372 1,555 866 533
--------- -------- --------- ---------
Cash and cash equivalents at end of period $ 7272,818 $ 1563,372 $ 480
===========================================================================================================1,555 $ 866
========= ======== ========= =========
The accompanying Notes to Financial Statements are an integral part of these
statements.
2741
29
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Alabama Gas Corporation (Alagasco), a wholly-owned subsidiary of- -------------------------------------------------------------------------------
Energen Corporation (Energen or the Company) is a diversified energy holding
company engaged primarily in the largestacquisition, development, exploration and
production of oil and gas in the continental United States (oil and gas
operations) and in the purchase, distribution, and sale of natural gas
distribution utility in the State of
Alabama, serving customers primarilyprincipally in central and north Alabama.Alabama (natural gas distribution). The
following is a description of itsthe Company's significant accounting policies and
practices.
On December 5, 2001, the Board of Directors of the Company approved a change in
the Company's fiscal year end from September 30 to December 31, effective
January 1, 2002. A transition report was filed on Form 10-Q for the period
October 1, 2001 to December 31, 2001. Alagasco has continued on a September 30
fiscal year for rate-setting purposes (rate year) and reports on a calendar
year for the Securities and Exchange Commission and all other financial
accounting reporting purposes.
A. PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the
accounts of the Company and its subsidiaries, principally Energen
Resources Corporation and Alabama Gas Corporation (Alagasco), after
elimination of all significant intercompany transactions in
consolidation. Certain reclassifications have been made to conform the
prior years' financial statements to the current-year presentation.
B. OIL AND GAS OPERATIONS
PROPERTY AND RELATED DEPLETION: Energen Resources follows the
successful efforts method of accounting for costs incurred in the
exploration and development of oil and gas reserves. Lease acquisition
costs are capitalized initially, and unproved properties are reviewed
periodically to determine if there has been impairment of the carrying
value, with any such impairment charged to exploration expense
currently. Exploratory drilling costs are capitalized pending
determination of proved reserves. If proved reserves are not
discovered, the exploratory drilling costs are expensed. Other
exploration costs, including geological and geophysical costs, are
expensed as incurred. All development costs are capitalized.
Depreciation, depletion and amortization expense is determined on a
field-by-field basis using the unit-of-production method based on
proved reserves. Anticipated abandonment and restoration costs are
capitalized and depreciated over the estimated useful life of the
related asset. The costs and related accumulated depletion of
properties sold or retired are removed from the accounts and the
resulting gains or losses are included in discontinued operations.
OPERATING REVENUE: Energen Resources utilizes the sales method of
accounting to recognize oil and gas production revenue. Under the
sales method, revenue is recognized for the Company's total takes of
oil and gas production that are sold to and payable by its customers.
Over-production liabilities are established only when it is estimated
that a property's over-produced volumes exceed the net share of
remaining reserves for such property. Energen Resources had no
material production imbalances at December 31, 2002.
DERIVATIVE COMMODITY INSTRUMENTS: Energen Resources periodically
enters into cash flow derivative commodity instruments to hedge its
exposure to price fluctuations on oil, natural gas and natural gas
liquids production. Such instruments include regulated natural gas and
crude oil futures contracts traded on the New York Mercantile Exchange
(NYMEX) and over-the-counter swaps, collars and basis hedges with
major energy derivative product specialists. The counterparties to the
commodity instruments are investment banks and energy-trading firms.
In some contracts, the amount of credit allowed before Energen
Resources must post collateral for out-of-the-money hedges varies
depending on the credit rating of the Company's debt. In cases where
this arrangement exists, generally the Company's credit ratings must
be maintained at investment grade status to have available
counterparty credit.
42
The Company adopted Statement of Financial Accounting Standard (SFAS)
No. 133 (subsequently amended by SFAS Nos. 137 and 138), "Accounting
for Derivative Instruments and Hedging Activities," on October 1,
2000. This statement requires all derivatives to be recognized on the
balance sheet and measured at fair value. If a derivative is
designated as a cash flow hedge, the Company is required to measure
the effectiveness of the hedge, or the degree that the gain (loss) for
the hedging instrument offsets the loss (gain) on the hedged item, at
each reporting period. The effective portion of the gain or loss on
the derivative instrument is recognized in other comprehensive income
as a component of equity and subsequently reclassified into earnings
when the forecasted transaction affects earnings. The ineffective
portion of a derivative's change in fair value is required to be
recognized in earnings immediately. Derivatives that do not qualify
for hedge treatment under SFAS No. 133 must be recorded at fair value
with gains or losses recognized in earnings in the period of change.
As of December 31, 2002, all of the Company's derivatives qualified
for cash flow hedge accounting.
Additionally, the Company may also enter into derivatives that do not
qualify for cash flow hedge accounting but are considered by
management to represent valid economic hedges and are accounted for as
mark-to-market transactions. These economic hedges may include, but
are not limited to, basis hedges without a corresponding NYMEX hedge,
put options and hedges on non-operated or other properties for which
all of the necessary information to qualify for cash flow hedge
accounting is either not readily available or subject to change.
All hedge transactions are subject to the Company's risk management
policy as approved by the Board of Directors. The policy's objective
is to preserve revenues from forecasted sales and does not permit
speculative positions. The Company formally documents all
relationships between hedging instruments and hedged items, as well as
its risk management objective and strategy for undertaking the hedge.
This process includes specific identification of the hedging
instrument and the hedge transaction, the nature of the risk being
hedged and how the hedging instrument's effectiveness in hedging the
exposure to the hedged transaction's variability in cash flows
attributable to the hedged risk will be assessed. Both at the
inception of the hedge and on an ongoing basis, the Company assesses
whether the derivatives that are used in hedging transactions are
highly effective in offsetting changes in cash flows of hedged items.
The Company discontinues hedge accounting if a derivative has ceased
to be a highly effective hedge.
C. NATURAL GAS DISTRIBUTION
UTILITY PLANT AND DEPRECIATION
UtilityDEPRECIATION: Property, plant and equipment is
stated at originalcost. The cost whichof utility plant includes an allowance for
funds used during construction. Maintenance is charged for the cost of
normal repairs and the renewal or replacement of an item of property
which is less than a retirement unit. When property which represents a
retirement unit is replaced or removed, the cost of such property is
credited to utility plant and, together with the cost of removal less
salvage, is charged to the accumulated reserve for depreciation.
Depreciation is provided on the straight-line method over the
estimated useful lives of utility property at rates established by the
Alabama Public Service Commission (APSC). Approved depreciation rates
averaged approximately 4.34.5 percent in 1995, 1994the year ended December 31,
2002, for the three months ended December 31, 2001 and 1993.
B.for the years
ended September 30, 2001 and 2000.
INVENTORIES: Inventories, which consist primarily of gas stored
underground, are stated at average cost.
OPERATING REVENUE AND GAS COSTSCOSTS: In accordance with industry practice,
Alagasco records revenuenatural gas distribution revenues on a monthlymonthly- and
cycle billingcycle-billing basis. Alagasco extends credit to its residential and industrial
utility customers which are located primarily in central and north Alabama. The commodity cost of purchased gas applicable to
gas delivered to customers but not yet billed under the cycle billingcycle-billing
method is deferred as a current asset.
C.REGULATORY ACCOUNTING: Alagasco is subject to the provisions of SFAS
No. 71, "Accounting for the Effects of Certain Types of Regulation."
In general, SFAS No. 71 requires utilities to capitalize or defer
certain costs or revenues, based upon approvals received from
regulatory authorities, to be recovered from or refunded to customers
in future periods.
43
DERIVATIVE COMMODITY INSTRUMENTS: As required by SFAS No. 133,
Alagasco recognizes all derivatives as either assets or liabilities on
the balance sheet. Any gains or losses are passed through to customers
using the mechanisms of the Gas Supply Adjustment (GSA) rider in
accordance with Alagasco's APSC approved tariff, as required by SFAS
No. 71.
TAXES ON REVENUES: Collections and payments of excise taxes are
reported on a gross basis. The amounts included in taxes other than
income taxes on the consolidated statements of income are as follows:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Taxes on revenues $21,591 $4,969 $28,766 $19,749
------- ------ ------- -------
Total $21,591 $4,969 $28,766 $19,749
======= ====== ======= =======
D. INCOME TAXES
Alagasco filesThe Company uses the liability method of accounting for income taxes
in accordance with SFAS No. 109, "Accounting for Income Taxes." Under
this method, a deferred tax asset or liability is recognized for the
estimated future tax effects attributable to temporary differences as
well as tax credit carryforwards. Deferred tax assets and liabilities
are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected
to be recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in the period of
the change. The Company and its subsidiaries file a consolidated
federal income tax return with its parent. The
consolidatedreturn. Consolidated federal income taxes are
allocated to the appropriate subsidiaries using the separate return
method.
Deferred income taxes reflect the impact of
temporary differences between the tax basis of assets and liabilities and their
carrying amounts for financial reporting purposes, and are measured in
compliance with enacted tax laws. Investment tax credits have been deferred
and are being amortized over the lives of the related assets.
D.E. CASH EQUIVALENTS
AlagascoThe Company includes highly liquid marketable securities and debt
instruments purchased with a maturity of three months or less in cash
equivalents.
28F. EARNINGS PER SHARE
The Company's basic earnings per share amounts have been computed
based on the weighted-average number of common shares outstanding.
Diluted earnings per share amounts reflect the assumed issuance of
common shares for all potentially dilutive securities (see Note 9).
G. STOCK-BASED COMPENSATION
The Company currently reports stock-based employee compensation
through the disclosure-only provisions of SFAS No. 123, "Accounting
for Stock-Based Compensation." Accordingly, no compensation expense
has been recognized for its stock options. Had compensation cost for
these options been determined in accordance with SFAS No. 123, the
Company's net income and diluted earnings per share would have been as
follows:
44
30
2. LONG-TERM DEBT AND NOTES PAYABLE
Long-term debt consists of the following:
=============================================================================================================
AS OF SEPTEMBERThree Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, (IN THOUSANDS) 1995 1994
=============================================================================================================
Medium term notes, interest ranging from 5.4% to 7.7%, for notes
redeemable December 1, 1998 to June 27, 2025 $100,000 $50,000
First Mortgage Bonds, 11% Series H, defeased during fiscal
year 1995 -- 7,500
9% debentures, defeased during fiscal year 1995 -- 28,758
Mortgage note payable, paid in full during fiscal year 1995 -- 956
- -------------------------------------------------------------------------------------------------------------
Total 100,000 87,214
Less amounts due within one year -- 2,823
- -------------------------------------------------------------------------------------------------------------
Total $100,000 $84,391
=============================================================================================================
During the fourth quarter, Alagasco deposited $37.6 million into an irrevocable
trust to complete an in-substance defeasance of the 9 percent debentures and 11
percent Series H First Mortgage Bonds. The funds in the trust, primarily
obtained through the issuance of medium-term notes and short-term borrowings,
will be used solely to satisfy the principal, interest, and call premium of the
defeased debt. Accordingly, the debt and related accrued interest have been
excluded from the 1995 consolidated balance sheet. No gain or loss was recorded
in the financial statements as the APSC has granted Alagasco regulatory relief
related to the income statement impact of this defeasance.
The aggregate maturities of long-term debt for the next five years are as
follows:
=======================================================================================================
YEARS ENDING SEPTEMBERSeptember 30,
(IN THOUSANDS)
=======================================================================================================
1996 1997 1998 1999(in thousands) 2002 2001 2001 2000
- ------------------------------------------------------------------------------------------------------------------- ------------ ------------- -------------
-- -- -- $5,350 --
=======================================================================================================Net income
As reported $ 68,639 $ 3,658 $ 67,896 $ 53,018
Stock based compensation expense included
in reported net income, net of tax 2,879 911 2,894 4,545
Stock based compensation expense
determined under fair value based method,
net of tax (3,472) (822) (3,142) (3,539)
---------- --------- ---------- ----------
Pro forma $ 68,046 $ 3,747 $ 67,648 $ 54,024
---------- --------- ---------- ----------
Diluted earnings per average common share
As reported $ 2.03 $ 0.12 $ 2.18 $ 1.75
Pro forma $ 2.01 $ 0.12 $ 2.18 $ 1.78
---------- --------- ---------- ----------
Basic earnings per average common share
As reported $ 2.04 $ 0.12 $ 2.21 $ 1.76
Pro forma $ 2.02 $ 0.12 $ 2.20 $ 1.79
========== ========= ========== ==========
29
The Company uses the Black-Scholes pricing model to calculate the fair
values of the options awarded, which are included in the pro forma
results above. For purposes of this valuation the following
assumptions were used to derive the fair values: a seven-year time of
exercise; an annualized volatility rate of 34.67 percent, 36.35
percent and 34.64 percent for the three months ended December 31,
Energen2001, and Alagasco have short-term credit linesthe years ended September 30, 2001 and other credit facilities2000, respectively; a
risk-free interest rate of $110 million available3.36 percent, 4.14 percent, and 5.76
percent for the three months ended December 31, 2001, and the years
ended September 30, 2001 and 2000, respectively; and a dividend yield
of 3.12 percent, 2.55 percent and 3.53 percent on options without
dividend equivalents for the three months ended December 31, 2001, and
the years ended September 30, 2001 and 2000, respectively. Options
with dividend equivalents assume no dividend yield for all periods
presented. The weighted-average grant-date fair value of options
granted for the three-months ended December 31, 2001, was $9.74 for
options granted with dividend equivalents and $6.52 for options
granted without dividend equivalents; $12.66 for options granted with
dividend equivalents and $9.27 for options granted without dividend
equivalents during the year-ended September 30, 2001; and $5.91 for
options granted without dividend equivalents in the year-ended
September 30, 2000. There were no options granted in the year ended
December 31, 2002.
H. ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to either entity for working capital needs. The
following is a summarymake estimates and assumptions that affect the reported
amounts of information relatingassets and liabilities at the date of the financial
statements and the reported amount of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Significant estimates with regard to notes payable to banks:
============================================================================================================
AS OF SEPTEMBER 30, (IN THOUSANDS) 1995 1994 1993
============================================================================================================
Alagasco outstanding $ -- $ 4,000 $ 29,000
Other Energen outstanding 32,300 2,000 11,000
Available for borrowings 77,700 104,000 70,000
- ------------------------------------------------------------------------------------------------------------
Total $110,000 $110,000 $110,000
============================================================================================================
Maximum amount outstanding at any month-end $ 5,000 $ 60,000 $ 29,000
Average daily amount outstanding $ 447 $ 13,460 $ 23,071
Weighted average interest rates based on:
Average daily amount outstanding 5.69% 3.32% 3.41%
Amount outstanding at year-end -- 5.17% 3.35%
============================================================================================================
Total interest expensethese financial statements
include the estimate of proved oil and gas reserves and the related
present value of estimated future net revenues therefrom (see Note
19).
2. REGULATORY MATTERS
- -------------------------------------------------------------------------------
All of Alagasco's utility operations are conducted in 1995, 1994 and 1993 was $9,652,000, $8,320,000, and
$7,487,000, respectively.
3. REGULATORY
As an Alabama utility,the state of Alabama.
Alagasco is subject to regulation by the APSC which in
1983, established the Rate
Stabilization and Equalization (RSE) rate-setting process.process in 1983. RSE was
extended forwith modifications in 2002, 1996, 1990, 1987 and 1985. On June 10,
2002, the third time on December 3, 1990,APSC extended Alagasco's rate-setting methodology, RSE, without
change, for a three-year period. Undersix-year period through January 1, 2008. Alagasco's allowed range
of return on equity remains 13.15 percent to 13.65 percent throughout the termsterm
of that extension, RSE shall continue
after November 30, 1993, unless, after noticethe order, subject to change in the Company, the Commission
votes to either modify or discontinue its operation. On October 4, 1993, the
Commission unanimously voted to extend RSE until such time as certain hearings
mandated by the Energy Policy Act of 1992 (Energy Act) in connection with
integrated resource planning and demand side management programs are completed.
The Energy Act proceedings are expected to conclude during fiscal 1996 at which
time it is expectedevent that the Commission, will begin reviewing Alagasco's RSE.
No time table for review has yet been established.following a
generic rate of return hearing, adjusts the equity returns of all major energy
utilities operating under a similar methodology. Under RSE as extended, the
APSC conducts quarterly reviews to determine, based on Alagasco's projections
and fiscal year-to-date performance, whether Alagasco's return on average equity forat
the fiscalend of the rate year will be within the allowed range of 13.15 percent to
13.65 percent. Reductions in rates can be made quarterly to bring the projected
return within the allowed range; increases, however, are allowed only once each
fiscalrate year, effective December 1, and cannot exceed 4 percent of prior-year
revenues. RSE limits the utility's equity upon which a return is permitted to
60 percent of total capitalization and provides for certain cost control
measures designed to monitor the Company'sAlagasco's operations and maintenance (O&M)
expense. IfUnder the inflation-based cost control measurement established by the
APSC, if the percentage change in O&M expense per customer falls within a range
of 1.25 percentage points above or below the percentage change in the Consumer Price Index
For All Urban CustomersConsumers (index range), no adjustment is required. If however,the change
in O&M expense per customer exceeds the index range, three-quarters of the
difference will beis returned to
the45
customers. To the extent O&M expense per customerthe change is less than the index range, the utility
will benefitbenefits by one-half of the difference through future rate adjustments. Under RSEThe
increase in O&M expense per customer was above the index range for the rate
year ended September 30, 2002; as extended, a $1.1result, the utility returned to customers
$0.3 million decrease in revenue became effective October 1, 1994,pre-tax through rate adjustments under the provisions of RSE. A
$12.4 million, $16.3 million and a $5.2$9.1 million annual increase in revenuerevenues
became effective December 1, 1994.
Effective December 15, 1990, the APSC approved2002, 2001 and 2000, respectively, under RSE as
extended.
Alagasco calculates a temperature adjustment to customers' monthly bills to
substantially remove the effect of departures from normal temperaturetemperatures on
Alagasco's earnings. The calculation is performed monthly, and
the adjustmentsAdjustments to customers' bills are made in the same
monthbilling cycle in which the weather variation occurs. 30
32
The Company'stemperature adjustment
applies to residential, small commercial and small industrial customers.
Alagasco's rate schedules for natural gas distribution charges contain a Gas
Supply Adjustment (GSA)GSA
rider, established in 1993, which permits the pass-through to customers of
changes in the cost of gas supply, including Gas
Supply Realignment (GSR) surcharges imposed bysupply.
The APSC approved an Enhanced Stability Reserve (ESR), beginning fiscal year
1998 with an approved maximum funding level of $4 million, to which Alagasco
may charge the Company's suppliersfull amount of: (1) extraordinary O&M expenses resulting from
changesforce majeure events such as storms, severe weather, and outages, when one or a
combination of two such events results in gas supply purchasesmore than $200,000 of additional O&M
expense during a rate year; or (2) individual industrial and commercial
customer revenue losses that exceed $250,000 during the rate year, if such
losses cause Alagasco's return on average equity to fall below 13.15 percent.
During the year ended September 30, 2001, Alagasco charged $1.2 million against
the ESR related to extraordinary bad debt expense and revenue losses from
certain large industrial customers. Following a year in which a charge against
the implementation of
FERC Order 636.
On June 12, 1995,ESR is made, the APSC approved Alagasco's applicationprovides for accretions to issue $50the ESR of no more than
$40,000 monthly until the maximum funding level is achieved. The ESR balances
of $3 million of new debt. A portion of the proceeds was used to redeem all of Alagasco's 9
percent debenturesat December 31, 2002, and 11 percent First Mortgage Bonds. In connection with the
early call of the redeemed debt, Alagasco paid an early call premium of
approximately $1.3$2.7 million during the fourth quarter. Because the APSC Order
authorized Alagasco to collect the early call premium through customer rates
during the fiscal year endingat December 31, 2001 and
September 30, 1996,2001, respectively, are included in the consolidated financial
statements.
At December 31, 2002, Alagasco recordedhad a $18.7 million accrued obligation related
to its salaried and union pension plans. In accordance with SFAS No. 71,
Alagasco has established a regulatory asset of $1.3$14.7 million duringfor the fourth quarter endingportion of
the accrued obligation to be recovered through rates in future periods.
The excess of total acquisition costs over book value of net assets of acquired
municipal gas distribution systems is included in utility plant and is being
amortized through Alagasco's rate-setting mechanism on a straight-line basis
over approximately 23 years. At December 31, 2002, December 31, 2001 and
September 30, 1995.
In accordance with APSC-directed regulatory accounting procedures, Alagasco in
1989 began returning to customers excess utility deferred taxes which resulted
from a reduction in2001, the federal statutory tax rate from 46 percent to 34
percent using the average rate assumption method. This method provides for the
return to ratepayers of excess deferred taxes over the lives of the related
assets. In 1993 those excess taxesnet acquisition adjustments were reduced as a result of a federal tax
rate increase from 34 percent to 35 percent. Approximately $2.9$13.8 million, of the
remaining excess utility deferred taxes is being returned to ratepayers over
approximately 15 years.
FERC REGULATION: On March 15, 1995, Southern Natural Gas Company (Southern)
filed a comprehensive settlement with the FERC in the form of a Stipulation$12.1
million and Agreement (the Settlement) to resolve all issues in Southern's six pending rate
cases, as well as to resolve all GSR and transition cost issues resulting from
the implementation of FERC Order 636. The Settlement is supported by parties
representing more than 90 percent of the firm transportation demand on
Southern's system, including local distribution companies (including Alagasco),
municipal distribution systems, major gas producers, large industrial end
users, marketers, and state commissions (including the APSC).
On September 29, 1995, the FERC issued its Order Accepting Settlement, Severing
Contesting parties, and Issuing Certificates and Approving Abandonment
(Settlement Order). The Settlement Order approves the Settlement with minor
modifications. Contesting parties had 30 days from the date of the Settlement
Order to file motions for rehearing and several such motions were timely filed.
Until such motions are ruled on by the FERC, the Settlement Order is not
considered to be final.
Specifically, the Settlement provides for the following: (1) the resolution of
all cost of service and rate design issues in Southern's six pending rate cases
and the establishment of reduced rates for the purpose of calculating rate case
refunds; (2) the implementation of reduced settlement rates on an interim basis
for supporting parties commencing March 1, 1995 (by order dated April 4, 1995,
FERC approved these interim rates pending its final review of the merits of the
Settlement); (3) the resolution of all GSR and other transition cost issues
resulting from FERC Order 636; (4) lower GSR cost recovery through the
reduction and earlier payout of GSR costs; (5) a three-year moratorium on
general rate increases; and (6) the resolution and disposition of all rate case
and GSR refunds for supporting parties. With respect to this last point, the
Settlement provides that all rate case refunds will be used to offset a portion
of Southern's remaining GSR liability. In addition, as a result of the
recalculated GSR surcharges for the period January 1, 1994, to February 28,
1995, Southern will refund over-collected GSR costs. Neither the total amount
of this refund nor Alagasco's share has yet been determined; therefore, no
amounts have been recorded in the financial statements. In the Settlement
filing with FERC, Southern has represented that the Settlement will allow
Southern and the supporting parties to resolve all issues relating to GSR and
other transition costs, the majority of which costs will be collected by the
end of calendar 1995. Alagasco estimates that it has a remaining GSR liability
of approximately $2.4$12.4 million, to be paid through December 1995 and
approximately $2.6 million in other transition costs to be paid through June
1998 and that it has recorded such amounts in the financial statements. Because
these costs will be recovered in full from Alagasco's customers in a timely
31
33
manner through the GSA rider of Alagasco's Tariff, the Company has recorded a
corresponding regulatory asset in the accompanying financial statements.
4. CAPITAL STOCK
Alagasco's authorized common stock consists of 3 million, $0.01 par value
common shares. At September 30, 1995 and 1994, 1,972,052 shares were issued
and outstanding. Alagasco is authorized to issue 120,000 shares of preferred
stock, par value $0.01 per share, in one or more series. There are no shares
currently outstanding.
5. INCOME TAXES
The components of income taxes consistrespectively.
3. LONG-TERM DEBT AND NOTES PAYABLE
- -------------------------------------------------------------------------------
Long-term debt consisted of the following:
============================================================================================================
FOR THE YEARSDECEMBER 31, December 31, September 30,
(in thousands) 2002 2001 2001
------------ ------------ -------------
Energen Corporation:
Medium-term Notes, interest ranging from 6.81% to
8.09%, for notes redeemable September 15, 2003,
to February 15, 2028 $353,000 $363,000 $363,000
Series 1993 Notes -- 8,881 8,881
Alabama Gas Corporation:
Medium-term Notes, interest ranging from 6.25% to
7.97%, for notes redeemable September 15, 2003,
to September 23, 2026 110,000 115,000 115,000
6.25% Notes, redeemable September 1, 2016 39,758 40,000 40,000
6.75% Notes, redeemable September 1, 2031 34,775 35,000 35,000
-------- -------- --------
Total 537,533 561,881 561,881
Less amounts due within one year 23,000 16,072 16,072
Less unamortized debt discount 1,579 1,676 1,699
-------- -------- --------
Total $512,954 $544,133 $544,110
======== ======== ========
46
The aggregate maturities of Energen's long-term debt for the next five years
are as follows:
Years ending December 31, (in thousands)
- --------------------------------------------------------------------------
2003 2004 2005 2006 2007
- ------- ------- ------- ------- ------
$23,000 $10,000 $10,000 $20,000 $7,000
The aggregate maturities of Alagasco's long-term debt for the next five years
are as follows:
Years ending December 31, (in thousands)
- ----------------------------------------------------------------------
2003 2004 2005 2006 2007
- ------- --- ------- ------- ------
$15,000 $-- $10,000 $10,000 $7,000
At December 31, 2002, the Company was not subject to restrictions on the
payment of dividends. The Company is in compliance with the covenants under the
various long-term debt agreements. Except as discussed below, debt covenants
address routine matters such as timely payment of principal and interest,
maintenance of corporate existence and restrictions on liens. Payments with
respect to Alagasco's 6.25% Notes and 6.75% Notes are insured by Ambac
Assurance Corporation. Under the insurance agreement, Alagasco agreed that it
will not dispose of distribution plant assets if, after such disposition, its
distribution plant will be less than $200 million. Alagasco's distribution
plant exceeded $200 million at December 31, 2002. All of the Company's debt is
unsecured.
Energen and Alagasco had short-term credit lines and other credit facilities of
$267 million available as of December 31, 2002, for working capital needs;
Alagasco has been authorized to borrow up to $70 million of the available
credit lines by the APSC. The following is a summary of information relating to
notes payable to banks:
DECEMBER 31, December 31, September 30,
(in thousands) 2002 2001 2001
------------ ------------ -------------
Energen outstanding $100,000 $ 5,000 $ 6,000
Alagasco outstanding 13,000 19,000 1,000
-------- -------- --------
Notes payable to banks 113,000 24,000 7,000
Available for borrowings 154,000 196,000 213,000
-------- -------- --------
Total $267,000 $220,000 $220,000
-------- -------- --------
Maximum amount outstanding at any month-end $113,000 $ 24,000 $177,000
Average daily amount outstanding $ 85,644 $ 16,717 $ 80,681
Weighted average interest rates based on:
Average daily amount outstanding 2.28% 2.53% 6.05%
Amount outstanding at year-end 1.88% 2.18% 2.97%
-------- -------- --------
Alagasco maximum amount outstanding at any month-end $ 21,000 $ 19,000 $ 62,000
Alagasco average daily amount outstanding $ 3,304 $ 11,761 $ 40,066
Alagasco weighted average interest rates based on:
Average daily amount outstanding 2.18% 2.47% 5.31%
Amount outstanding at year-end 1.78% 2.16% 2.97%
-------- -------- --------
Energen's total interest expense was $43,713,000 for the year ended December
31, 2002, $10,634,000 for the three months ended December 31, 2001 and
$42,070,000 and $37,769,000 for the years ended September 31, 2001 and 2000,
respectively. Total interest expense at Alagasco was $14,557,000 for the year
ended December 31, 2002, $3,680,000 for the three months ended December 31,
2001 and $12,316,000 and $9,870,000 for the years ended September 30, 2001 and
2000, respectively, at Alagasco.
47
4. INCOME TAXES
- -------------------------------------------------------------------------------
The components of Energen's income taxes consisted of the following:
Three Months
YEAR ENDED SEPTEMBEREnded Year Ended Year Ended
DECEMBER 31, December 31, September 30, (IN THOUSANDS) 1995 1994 1993
============================================================================================================September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Taxes estimated to be payable currently:
Federal $7,633 $ 9,664 $4,9117,370 $ 3,686 $ 8,601 $ 10,412
State 759 959 496
- ------------------------------------------------------------------------------------------------------------546 1,537 1,309 1,918
------- ------- ------- --------
Total current 8,392 10,623 5,407
- ------------------------------------------------------------------------------------------------------------7,916 5,223 9,910 12,330
------- ------- ------- --------
Taxes deferred:
Federal (326) (2,689) 8679,065 (7,211) 3,073 (6,027)
State 16 (216) 135
- ------------------------------------------------------------------------------------------------------------3,528 (1,396) 1,828 179
------- ------- ------- --------
Total deferred (310) (2,905) 1,002
- ------------------------------------------------------------------------------------------------------------12,593 (8,607) 4,901 (5,848)
------- ------- ------- --------
Total income tax expense $8,082(benefit)
from continuing operations $20,509 $(3,384) $14,811 $ 7,718 $6,409
============================================================================================================6,482
======= ======= ======= ========
32
34In addition, Energen recorded income tax expense, related to income from
discontinued operations, of $2,300,000 in current income tax expense and
($2,126,000) in deferred income tax expense for the year ended December 31,
2002, $59,000 in current income tax expense for the three months ended December
31, 2001, and $1,165,000 and $307,000 in current income tax expense for the
years ended September 30, 2001 and 2000, respectively.
The components of Alagasco's income taxes consisted of the following:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Taxes estimated to be payable currently:
Federal $ 7,763 $ 9,167 $ 15,456 $ 15,225
State 1,001 1,181 1,539 1,486
------- -------- -------- --------
Total current 8,764 10,348 16,995 16,711
------- -------- -------- --------
Taxes deferred:
Federal 7,974 (7,807) (3,193) (2,215)
State 1,087 (994) (354) (172)
------- -------- -------- --------
Total deferred 9,061 (8,801) (3,547) (2,387)
------- -------- -------- --------
Total income tax expense from continuing
operations $17,825 $ 1,547 $ 13,448 $ 14,324
======= ======== ======== ========
Temporary differences and carryforwards which givegave rise to a significant
portion of Energen's and Alagasco's deferred tax assets and liabilities for
19952002 and 1994 are2001 were as follows:
48
============================================================================================================
1995 1994
---------------------------------------------------------
AS OF SEPTEMBEREnergen Corporation
(in thousands) DECEMBER 31, 2002 December 31, 2001 September 30, (IN THOUSANDS)2001
---------------------- ---------------------- ----------------------
CURRENT NONCURRENT CURRENT NONCURRENT
============================================================================================================Current Noncurrent Current Noncurrent
------- ---------- ------- ---------- ------- ----------
Deferred tax assets:
Deferred investmentMinimum tax creditscredit $ -- $ 1,386$64,756 $ -- $57,441 $ 1,567
Regulatory liabilities -- 2,229$56,043
Pension and other costs 5,326 7,056 7,165 -- 2,5856,574 --
Unbilled revenue 1,565and
other costs 9,082 -- 1,4549,037 -- 1,942 --
Enhanced stability reserve 1,120 -- 1,022 -- 1,016 --
Allowance for doubtful
accounts 3,316 -- 4,236 -- 3,631 --
Insurance and accruals 1,9232,736 -- 1,3392,402 -- Gas supply adjustment 930 -- 1,123 --
Accrued vacation 988 -- 981 --
Allowance for uncollectible accounts 902 -- 8782,384 --
Other net 2,022 52 1,477 96
- ------------------------------------------------------------------------------------------------------------
Subtotal 8,330 3,667 7,252 4,248
Valuation allowancecomprehensive income 5,980 3,053 -- -- -- --
- ------------------------------------------------------------------------------------------------------------Other, net 6,644 2,153 9,894 1,338 5,979 1,420
------- ------- ------- ------- ------- -------
Total deferred tax assets $8,330 $ 3,667 $7,252 $ 4,248
============================================================================================================34,204 77,018 33,756 58,779 21,526 57,463
------- ------- ------- ------- ------- -------
Deferred tax liabilities:
Depreciation and
basis differences $ -- $19,297 $53,622 -- $17,704
Pension and other benefit costs 91249,217 -- 1,45744,165
Minimum pension liability -- 7,056 -- -- -- --
Other comprehensive income -- -- 3,644 1,151 8,676 1,254
Other, net 2 713 71 248
- ------------------------------------------------------------------------------------------------------------263 7 476 5 425 5
------- ------- ------- ------- ------- -------
Total deferred tax liabilities 263 60,685 4,120 50,373 9,101 45,424
------- ------- ------- ------- ------- -------
Net deferred tax
assets (liabilities) $33,941 $16,333 $29,636 $ 914 $20,010 $1,528 $17,952
============================================================================================================8,406 $12,425 $12,039
======= ======= ======= ======= ======= =======
Alabama Gas Corporation
(in thousands) DECEMBER 31, 2002 December 31, 2001 September 30, 2001
---------------------- ---------------------- ----------------------
CURRENT NONCURRENT Current Noncurrent Current Noncurrent
------- ---------- ------- ---------- ------- ----------
Deferred tax assets:
Enhanced stability reserve $ 1,120 $ -- $ 1,022 $ -- $ 1,016 $ --
Unbilled revenue and
other costs 9,082 -- 9,037 -- 1,942 --
Insurance and accruals 3,418 -- 3,182 -- 2,817 --
Inventories 1,133 -- 1,022 -- 1,061 --
Allowance for
doubtful accounts 3,100 -- 4,197 -- 3,592 --
Pension and other costs -- 7,056 2,675 -- 2,239 --
Other, net 2,721 791 1,931 444 2,058 526
------- -------- ------- -------- ------- --------
Total deferred tax assets 20,574 7,847 23,066 444 14,725 526
------- -------- ------- -------- ------- --------
Deferred tax liabilities:
Depreciation and
basis differences -- 21,538 -- 15,975 -- 16,351
Minimum pension liability -- 7,056 -- -- -- --
Other, net 481 -- 246 -- 248 --
------- -------- ------- -------- ------- --------
Total deferred tax liabilities 481 28,594 246 15,975 248 16,351
------- -------- ------- -------- ------- --------
Net deferred tax
assets (liabilities) $20,093 $(20,747) $22,820 $(15,531) $14,477 $(15,825)
======= ======== ======= ======== ======= ========
The Company files a consolidated federal income tax return with all of its
subsidiaries. As of December 31, 2002, the amount of minimum tax credit which
can be carried forward indefinitely to reduce future regular tax liability is
$64.8 million. No valuation allowance with respect to deferred taxes is deemed
necessary, as the Company anticipates generating adequate future taxable income
to realize the benefits of all deferred tax assets on the consolidated balance
sheet.sheets.
Total income tax expense differsfor the Company differed from the amount which would
behave been provided by applying the statutory federal income tax rate of 35% to
pretax earnings before taxes from continuing operations as illustrated below:
49
============================================================================================================
FOR THEThree Months
YEAR ENDED SEPTEMBEREnded Year Ended Year Ended
DECEMBER 31, December 31, September 30, (IN THOUSANDS) 1995 1994 1993
============================================================================================================September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Income tax expense from continuing operations at
statutory federal income tax rate $8,331 $7,915 $6,729$ 31,883 $ 68 $ 28,314 $ 20,656
Increase (decrease) resulting from:
InvestmentNonconventional fuels tax credits (14,165) (3,481) (13,588) (14,405)
Enhanced oil recovery tax credits -- deferred (487) (487) (528)-- (25) (457)
Deferred investment tax credits (448) (112) (448) (448)
State income taxes, net of federal income
tax benefit 512 486 4122,465 28 1,754 1,421
Other, net (274) (196) (204)
- ------------------------------------------------------------------------------------------------------------774 113 (1,196) (285)
-------- ------- -------- --------
Total income tax expense $8,082 $7,718 $6,409
============================================================================================================(benefit)
from continuing operations $ 20,509 $(3,384) $ 14,811 $ 6,482
-------- ------- -------- --------
Effective income tax rate (%) 22.51 -- 18.31 10.98
======== ======= ======== ========
There were no tax-related balances dueTotal income tax expense for Alagasco differed from the amount which would have
been provided by applying the statutory federal income tax rate of 35% to
affiliates at September 30, 1995, or
1994.
33
35
6. RETIREMENT INCOMEearnings before taxes from continuing operations as illustrated below:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Income tax expense from continuing operations at
statutory federal income tax rate $ 15,886 $ 1,482 $ 13,812 $ 14,226
Increase (decrease) resulting from:
Deferred investment tax credits (448) (112) (448) (448)
State income taxes, net of federal income
tax benefit 1,236 116 799 874
Other, net 1,151 61 (715) (328)
-------- ------- -------- --------
Total income tax expense from
continuing operations $ 17,825 $ 1,547 $ 13,448 $ 14,324
-------- ------- -------- --------
Effective income tax rate (%) 39.27 36.54 34.08 35.24
======== ======= ======== ========
5. EMPLOYEE BENEFIT PLANS
AND OTHER BENEFITS
All information presented concerning retirement income and other benefit plans
includes other affiliates of Energen Corporation as well as Alagasco.- -------------------------------------------------------------------------------
The Company has two defined benefit non-contributory pension plans which coverplans: Plan A
covers a majority of the employees.employees and Plan B covers employees under certain
labor union agreements. Benefits are based on years of service and final
earnings. The Company's policy is to use the "projectedprojected unit credit"credit actuarial
method for funding and financial reporting purposes.
The status of the plans was as follows:
(in thousands) PLAN A
--------------------------------------------------------------
SEPTEMBER 30, September 30, June 30, June 30,
2002 2001 2001 2000
------------- ------------- -------- --------
Projected benefit obligation:
Balance at beginning of period $ 92,101 $ 90,613 $ 71,694 $ 73,841
Service cost 3,074 899 2,219 1,988
Interest cost 6,173 1,643 5,458 5,573
Actuarial loss (gain) 6,093 (46) 16,478 (2,642)
Benefits paid (6,042) (1,008) (5,236) (7,066)
--------- -------- -------- --------
Balance at end of period 101,399 92,101 90,613 71,694
--------- -------- -------- --------
50
Plan assets:
Fair value of plan assets at beginning of period 67,967 74,486 87,169 83,844
Actual return on plan assets (5,331) (5,510) (7,447) 10,391
Employer contributions 11,000 -- -- --
Benefits paid (6,042) (1,009) (5,236) (7,066)
--------- -------- -------- --------
Fair value of plan assets at end of period 67,594 67,967 74,486 87,169
--------- -------- -------- --------
Amounts recognized in the consolidated balance sheets:
Funded status of plan (33,805) (24,134) (16,127) 15,475
Unrecognized actuarial loss (gain) 30,565 12,996 6,001 (22,926)
Unrecognized prior service cost 2,027 2,262 2,321 2,555
Unrecognized net transition obligation (asset) -- (196) (261) (1,069)
--------- -------- -------- --------
Accrued pension asset (liability) $ (1,213) $ (9,072) $ (8,066) $ (5,965)
========= ======== ======== ========
(in thousands) PLAN B
--------------------------------------------------------------
SEPTEMBER 30, September 30, June 30, June 30,
2002 2001 2001 2000
------------- ------------- -------- --------
Projected benefit obligation:
Balance at beginning of period $ 17,945 $ 17,949 $ 17,002 $ 18,227
Service cost 396 80 255 265
Interest cost 1,422 320 1,267 1,361
Plan amendment 1,781 -- -- --
Actuarial loss (gain) 1,912 58 1,345 (487)
Benefits paid (1,468) (462) (1,920) (2,364)
-------- -------- -------- --------
Balance at end of period 21,988 17,945 17,949 17,002
-------- -------- -------- --------
Plan assets:
Fair value of plan assets at beginning of period 18,420 20,666 23,561 24,043
Actual return on plan assets (1,264) (1,784) (975) 1,882
Benefits paid (1,468) (462) (1,920) (2,364)
-------- -------- -------- --------
Fair value of plan assets at end of period 15,688 18,420 20,666 23,561
-------- -------- -------- --------
Amounts recognized in the consolidated balance sheets:
Funded status of plan (6,300) 475 2,717 6,559
Unrecognized actuarial loss (gain) 4,315 (481) (2,729) (6,458)
Unrecognized prior service cost 2,295 869 928 1,163
Unrecognized net transition obligation (asset) -- 43 57 114
-------- -------- -------- --------
Accrued pension asset (liability) $ 310 $ 906 $ 973 $ 1,378
======== ======== ======== ========
The components of net pension expense (income)were:
(in thousands) PLAN A
------------------------------------------------------------
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
2002 2001 2001 2000
------------ ------------ ------------- -------------
Components of net periodic benefit cost:
Service cost $ 3,074 $ 899 $ 2,219 $ 1,988
Interest cost 6,173 1,643 5,458 5,573
Expected long-term return on assets (6,145) (1,537) (5,778) (5,566)
Prior service cost amortization 235 59 235 235
Actuarial loss (gain) -- 2 422 --
Transition amortization (196) (65) (808) (808)
------- ------- ------- -------
Net periodic expense $ 3,141 $ 1,001 $ 1,748 $ 1,422
======= ======= ======= =======
51
(in thousands) PLAN B
------------------------------------------------------------
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
2002 2001 2001 2000
------------ ------------ ------------- -------------
Components of net periodic benefit cost:
Service cost $ 396 $ 80 $ 255 $ 265
Interest cost 1,422 320 1,267 1,361
Expected long-term return on assets (1,619) (406) (1,466) (1,577)
Prior service cost amortization 354 59 235 235
Actuarial loss (gain) -- -- (28) --
Transition amortization 43 14 57 57
------- ----- ------- -------
Net periodic expense $ 596 $ 67 $ 320 $ 341
======= ===== ======= =======
Net pension expense for Alagasco was $3,224,000 for the plan coveringyear ended December 31,
2002, $918,000 for the majority of employees (Plan A)three-months ended December 31, 2001 and $1,812,000 and
$1,466,000 for the years ended September 30, 1995, 19942001 and 1993, was $1,158,000, $15,000, and $(118,000),2000, respectively. The expense for the second plan covering employees under labor
union agreements (Plan B) for 1995, 1994 and 1993 was $339,000, $555,000 and
$557,000, respectively.
The funded status of the plans is as follows:
=============================================================================================================
AS OF JUNE 30, (IN THOUSANDS) PLAN A
PLAN B
=============================================================================================================
1995 1994 1995 1994
------------------------ ------------------------------------------------------------------------------
DECEMBER 31, December 31, September 30, September 30,
2002 2001 2001 2000
------------ ------------ ------------- -------------
Vested benefits $(46,073) $(48,354) $(13,499) $(12,860)
Nonvested benefits (5,912) (5,530) (2,083) (2,253)
- -------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation (51,985) (53,884) (15,582) (15,113)
Effects of salary progression (11,047) (10,332) -- --
- -------------------------------------------------------------------------------------------------------------
Projected benefit obligation (63,032) (64,216) (15,582) (15,113)
Fair value ofWeighted average rate assumptions in
pension actuarial calculations:
Discount rate 6.75% 7.50% 7.50% 8.00%
Expected long-term return on plan assets primarily equity and
fixed income securities 69,431 72,004 16,429 11,863
Unrecognized net gain 1,470 2,646 296 1,034
Unrecognized prior service cost 41 46 1,412 1,554
Unrecognized net transition obligation (asset) (5,111) (6,524) 396 452
Additional minimum liability -- -- -- (3,040)
- -------------------------------------------------------------------------------------------------------------
Accrued9.00% 9.00% 9.00% 8.25%
Rate of compensation increase 4.50% 4.50% 4.50% 5.50%
PLAN B
---------------------------------------------------------
DECEMBER 31, December 31, September 30, September 30,
2002 2001 2001 2000
------------ ------------ ------------- -------------
Weighted average rate assumptions in
pension asset (liability) $ 2,799 $ 3,956 $ 3,951 $ (3,250)
=============================================================================================================actuarial calculations:
Discount rate 6.75% 7.50% 7.50% 8.00%
Expected long-term return on plan assets 9.00% 9.00% 9.00% 8.25%
Under SFAS No. 87, "Employers' Accounting for Pensions," Energen recorded a
minimum pension liability for the accumulated benefit obligation in excess of
plan assets at December 31, 2002, of $21.7 million. Alagasco established a
regulatory asset of $14.7 million for the portion of this accrued benefit
obligation to be recovered through rates in future periods in accordance with
SFAS No. 71. An intangible asset was recorded for the unrecognized prior
service cost of $4.3 million and the balance of $1.7 million was recorded as a
component of accumulated other comprehensive income, net of tax. Subsequent to
December 31, 2002, Energen contributed an additional $9 million to pension Plan
A assets.
The Company has supplemental retirement plans with certain key executives
providing payments on retirement, termination, death or disability. Expense
(income) under these agreements for the year ended December 31, 2002, the three
months ended December 31, 2001 and the years ended September 30, 2001 and 2000
was $314,000, $(125,000), $381,000 and $372,000, respectively. At September 30,
19952002 and 1994, for both plans2001 and at June 30, 2001, the discount rate usedaccumulated post-retirement benefit
obligation related to measurethese agreements was $10,093,000, $9,198,000 and
$5,465,000, respectively, and the projected benefit obligation was 7.5 percent,$15,209,000,
$14,082,000, and $10,750,000, respectively. An accrued post-retirement benefit
liability of $5,860,000, $5,589,000 and $2,408,000 was recorded at December 31,
2002 and 2001 and September 30, 2001, respectively.
The Company recorded a minimum pension liability for supplemental retirement
plans of $4.2 million at December 31, 2002. A corresponding amount was
recognized as an intangible asset for the unrecognized prior service cost of
$81,000 and the expected
long-term ratebalance was recorded as a component of return on plan assets was 8.25 percent. The annual rateaccumulated other
comprehensive income, net of salary increase for the salaried plan was 5.5 percent for both years.
34
36
The componentstax, of net pension costs for 1995, 1994 and 1993 were:
=============================================================================================================
FOR THE YEARS ENDED SEPTEMBER 30,
(IN THOUSANDS) PLAN A PLAN B
=============================================================================================================
1995 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ----
Service cost $ 2,052 $ 1,873 $ 1,678 $ 224 $ 224 $ 187
Interest cost on projected
benefit obligation 4,728 4,550 4,097 1,095 1,042 1,018
Actual (return) on plan assets (8,787) (504) (6,858) (2,172) (372) (1,048)
Net amortization and deferral 2,106 (5,904) 965 1,192 (339) 400
Loss due to special termination
benefits 1,489 -- -- -- -- --
Settlement gain (430) -- -- -- -- --
- -------------------------------------------------------------------------------------------------------------
Net pension (income) expense $ 1,158 $ 15 $ (118) $ 339 $ 555 $ 557
=============================================================================================================
In 1995 the Company recognized a loss for special termination benefits of
$1,489,000 and a settlement gain of $430,000 pursuant to a voluntary early
retirement option offered to all salaried, non-officer employees of at least 58
years of age with a minimum of 5 years' service. Of the 55 eligible employees,
41 accepted.
Energen has deferred compensation plan agreements for certain key executives
providing for payments on retirement, death or disability. The deferred
compensation expense under these agreements for 1995, 1994 and 1993 was
$808,000, $461,000, and $650,000, respectively.$2.6 million.
In addition to providing pension benefits, the Company provides certain
post-retirement health care and life
52
insurance benefits. Substantially all of the Company's employees may become
eligible for suchcertain benefits if they reach normal retirement age while working
for the Company. In a prior year, the
company adopted SFAS No. 106, Employers' Accounting for Post-retirement
Benefits Other Than Pensions, with respect to the accrual of such costs for
salaried employees. During fiscal year 1994, the Company adopted SFAS 106 with
respect to such costs for employees under collective bargaining agreements.
There is no cumulative effect on the income statement resulting from the
adoption of SFAS 106 as the Company elected to amortize transition costs over a
20-year period. On December 6, 1993, the APSC adopted Order 4-3454 which allows
the Company to recover all costs accrued under SFAS 106 through rates.
While the Company has not adopted a formal funding policy, all of its accrued
post-retirement liability was funded at year-end. The expense for salaried
employees for the years ended September 30, 1995, 1994 and 1993 was $2,271,000,
$2,319,000, and $2,677,000, respectively. The expense for union employees was
$3,613,000, $3,685,000 and $982,000 during 1995, 1994 and 1993, respectively.
Prior to 1994, the Company recognized the cost of providing post-retirement
benefits for union employees on a "pay-as-you-go" basis. These benefits were
provided through a self-insurance arrangement and through insurance companies
whose premiums were based on the benefits paid during the year. The "projectedprojected unit credit"credit actuarial method was used to
determine the normal cost and actuarial liability.
35
37
A reconciliation of the estimatedThe status of the obligation ispost-retirement benefit programs was as follows:
=============================================================================================================
AS OF JUNE 30, (IN THOUSANDS)(in thousands) SALARIED EMPLOYEES
UNION EMPLOYEES
=============================================================================================================
1995 1994 1995 1994
---- ---- ---- -----------------------------------------------------------------
SEPTEMBER 30, September 30, June 30, June 30,
2002 2001 2001 2000
------------- ------------- -------- --------
AccumulatedProjected post-retirement benefit obligation:
Balance at beginning of period $ 35,888 $ 36,518 $ 29,811 $ 29,144
Service cost 831 261 1,095 1,092
Interest cost 2,120 649 2,327 2,203
Actuarial loss (gain) (6,264) (1,274) 4,964 (1,146)
Benefits paid (1,567) (266) (1,679) (1,482)
-------- -------- -------- --------
Balance at end of period 31,008 35,888 36,518 29,811
-------- -------- -------- --------
Plan assets:
Fair value of plan assets at beginning of period 30,921 36,142 41,004 35,494
Actual return on plan assets (7,073) (5,184) (4,520) 4,186
Company contribution 1,846 229 1,337 2,806
Benefits paid (1,567) (266) (1,679) (1,482)
-------- -------- -------- --------
Fair value of plan assets at end of period 24,127 30,921 36,142 41,004
-------- -------- -------- --------
Amounts recognized in the consolidated balance sheets:
Funded status of plan (6,881) (4,967) (376) 11,193
Unrecognized actuarial loss (gain) (1,259) (4,035) (8,667) (19,435)
Unrecognized net transition obligation $(20,757) $(21,296) $(29,600) $(24,564)
Plan assets 12,659 9,408 4,419 1,248
Unamortized amounts 7,550 11,751 24,237 21,357
- -------------------------------------------------------------------------------------------------------------(asset) 7,809 8,491 8,672 9,395
Company contribution 265 410 369 --
-------- -------- -------- --------
Accrued pension asset (liability) $ (66) $ (101) $ (2) $ 1,153
======== ======== ======== ========
(in thousands) UNION EMPLOYEES
-------------------------------------------------------------
SEPTEMBER 30, September 30, June 30, June 30,
2002 2001 2001 2000
------------- ------------- -------- --------
Projected post-retirement benefit liabilityobligation:
Balance at beginning of period $ (548)40,077 $ (137)40,986 $ (944)39,291 $ (1,959)
=============================================================================================================37,423
Service cost 807 218 733 1,876
Interest cost 2,800 727 3,095 2,852
Plan amendment 248 -- -- --
Actuarial loss (gain) (11,282) (1,450) 124 (1,635)
Benefits paid (2,041) (404) (2,257) (1,225)
-------- -------- -------- --------
Balance at end of period 30,609 40,077 40,986 39,291
-------- -------- -------- --------
Plan assets:
Fair value of plan assets at beginning of period 27,954 31,917 35,410 26,702
Actual return on plan assets (4,159) (4,628) (5,749) 3,928
Company contribution 2,141 1,069 4,513 6,005
Benefits paid (2,041) (404) (2,257) (1,225)
-------- -------- -------- --------
Fair value of plan assets at end of period 23,895 27,954 31,917 35,410
-------- -------- -------- --------
Amounts recognized in the consolidated balance sheets:
Funded status of plan (6,714) (12,123) (9,069) (3,881)
Unrecognized actuarial loss (gain) (7,869) (3,314) (7,269) (11,274)
Unrecognized prior service costs 237 -- -- --
Unrecognized net transition obligation (asset) 13,811 15,096 15,417 16,702
Company contribution 392 494 1,069 --
-------- -------- -------- --------
Accrued pension asset (liability) $ (143) $ 153 $ 148 $ 1,547
======== ======== ======== ========
53
Net periodic post-retirement benefit expense included the following:
(in thousands) SALARIED EMPLOYEES
---------------------------------------------------------------
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
2002 2001 2001 2000
------------ ------------ ------------- -------------
Components of net periodic benefit cost:
Service cost $ 831 $ 261 $ 1,095 $ 1,092
Interest cost 2,120 649 2,327 2,203
Expected long-term return on assets (1,678) (490) (1,994) (1,721)
Actuarial loss (gain) (434) (111) (1,098) (1,029)
Transition amortization 682 181 723 723
------- ----- ------- -------
Net periodic expense $ 1,521 $ 490 $ 1,053 $ 1,268
======= ===== ======= =======
(in thousands) UNION EMPLOYEES
---------------------------------------------------------------
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
2002 2001 2001 2000
------------ ------------ ------------- -------------
Components of net periodic benefit cost:
Service cost $ 807 $ 218 $ 733 $ 1,876
Interest cost 2,800 727 3,095 2,852
Expected long-term return on assets (2,472) (720) (1,723) (1,292)
Actuarial loss (gain) (93) (57) (336) (271)
Prior service cost 12 -- -- --
Transition amortization 1,285 321 1,285 1,285
------- ----- ------- -------
Net periodic expense $ 2,339 $ 489 $ 3,054 $ 4,450
======= ===== ======= =======
Net periodic post-retirement benefit costexpense for Alagasco was $3,493,000 for
the year ended December 31, 2002, $905,000 for the three months ended December
31, 2001 and $3,959,000 and $5,449,000 for the years ended September 30, 1995, 19942001
and 1993, included the following:2000, respectively.
=============================================================================================================
FOR THE YEAR ENDED SEPTEMBER 30, (IN THOUSANDS) SALARIED EMPLOYEES
UNION EMPLOYEES
=============================================================================================================
1995 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ----------------------------------------------------------------
DECEMBER 31, December 31, September 30, September 30,
2002 2001 2001 2000
------------ ------------ ------------- -------------
Service cost $ 512 $ 450 $ 464 $ 807 $ 481 $ --
Interest cost on accumulated post-retirement
benefit obligation 1,696 1,726 1,457 1,793 1,920 --
Amortization of transition obligation 723 723 842 1,285 1,285 --
Amortization ofWeighted average rate assumptions
in pension actuarial gains and losses -- -- 49 -- -- --
Deferred asset (gain) loss 539 (453) -- 424 -- --
Actual (return)calculations:
Discount rate 6.75% 7.50% 7.50% 8.00%
Expected long-term return on plan assets (1,199) (127) (135) (696) (1) --
- -------------------------------------------------------------------------------------------------------------
Net periodic post-retirement benefit expense $ 2,271 $2,319 $2,677 $3,613 $3,685 $ --
=============================================================================================================9.00% 9.00% 9.00% 8.25%
Rate of compensation increase 4.50% 4.50% 4.50% 5.50%
Health care cost trend rate GRADED RATE 7.50% 7.50% 7.50%
UNION EMPLOYEES
------------------------------------------------------------
DECEMBER 31, December 31, September 30, September 30,
2002 2001 2001 2000
------------ ------------ ------------- -------------
Weighted average rate assumptions
in pension actuarial calculations:
Discount rate 6.75% 7.50% 7.50% 8.00%
Expected long-term return on plan assets 9.00% 9.00% 9.00% 8.25%
Health care cost trend rate GRADED RATE 7.50% 7.50% 7.50%
The weighted average health care cost trend rate at December 31, 2002 for both
salaried and union employees is a 10% graduated rate down to 6% per year for
employees under age 65 and a 12% graduated rate down to 6% per year for
employees at or above age 65. This rate used in determining the accumulated
post-retirement benefit obligation was 8 percent in 1995 and 1994.
That assumption has a significantan effect on the amounts reported. For
example, with respect to salaried employees, increasing the
54
weighted average health care cost trend rate by 1 percentpercentage point would
increase the accumulated post-retirement benefit obligation by 3 percent$2,708,000 and
the net periodic post-retirement benefit cost by 2.1 percent.$283,000. For union employees,
increasing the weighted average health care cost trend rate by 1 percentpercentage
point would increase the accumulated post-retirement benefit obligation by
7.1 percent$2,152,000 and the net periodic post-retirement benefit cost by 7 percent. The weighted average discount rate$213,000.
For both defined benefit plans and other post-retirement plans, certain
financial assumptions are used in determining the accumulated post-retirementCompany's projected benefit
obligation was 7.5
percentobligation. These assumptions are examined periodically by the Company, and any
required changes are reflected in 1995 and 1994.the subsequent determination of projected
benefit obligations.
The Company has a long-term disability plan covering most salaried employees.
The Company had expense for the year ended December 31, 2002 of $304,000. The
Company had no expense for this plan in the three-months ended December 31,
2001 and in the years ended September 30, 2001 and 2000.
6. COMMON STOCK PLANS
- -------------------------------------------------------------------------------
A majority of Company employees are eligible to participate in the Energen
Employee Savings Plan (ESP) by investing a portion of their compensation in the
ESP, with the Company matching a part of the employee investment by
contributing Company common stock (new issue or treasury shares) or funds for
the purchase of Company common stock. The ESP also contains employee stock
ownership plan provisions. At December 31, 2002, a total of 148,594 common
shares were reserved for issuance under the ESP. Expense associated with
Company contributions to the ESP was $3,963,000 for the year ended December 31,
2002, $803,000 for the three months ended December 31, 2001, and $3,597,000 and
$3,381,000 for the years ended September 30, 1995, 19942001 and 1993 was $155,000,
$150,000,2000, respectively.
In 1992 the Company adopted the Energen Corporation 1992 Long-Range Performance
Plan which provides for the award of up to 1,000,000 performance units, with
each unit equal to the market value of one share of common stock, to eligible
employees based on predetermined performance criteria at the end of a four-year
award period. Under the Plan, a portion of the performance units is payable
with Company common stock; accordingly, 700,000 shares have been reserved for
issuance. Under the Plan, 76,120 and $129,000,102,860 performance units were awarded in
the years ended September 30, 2001 and 2000, respectively. According to the
provisions of the Plan, no additional performance units can be awarded after
September 30, 2001. In October 2001, the Company added provisions for the award
of future performance units, comparable to the 1992 Long-Range Performance
Plan, under the 1997 Stock Incentive Plan. Under the 1997 Stock Incentive Plan,
111,760 performance units were awarded in the three months ended December 31,
2001. The Company recorded expense of $2,136,250 for the year ended December
31, 2002, $722,500 for the three months ended December 31, 2001, and $2,311,000
and $4,448,000 for the years ended September 30, 2001 and 2000, respectively,
under the Plans.
On November 27, 1997, the Company adopted the Energen Corporation 1997 Stock
Incentive Plan. The 1997 Stock Incentive Plan, along with the Energen
Corporation 1988 Stock Option Plan, provides for the grant of incentive stock
options, non-qualified stock options, or a combination thereof to officers and
key employees. Options granted under the Plans provide for purchase of Company
common stock at not less than the fair market value on the date the option is
granted. In addition, the 1997 Stock Incentive Plan provides for the grant of
restricted stock with 22,775 shares awarded in the three-months ended December
31, 2001 and 57,190 and 12,500 shares awarded in the years ended September 30,
2001 and 2000, respectively. The sale or transfer of the shares is limited
during the restricted period. The Company recorded expense of $742,875 for the
year ended December 31, 2002, $188,000 for the three-months ended December 31,
2001 and $583,000 and $97,000 for the years ended September 30, 2001 and 2000,
respectively, related to the restricted stock. Under the 1988 Stock Option
Plan, 540,000 shares of Company common stock reserved for issuance have been
granted. Under the 1997 Stock Incentive Plan, an additional 1,500,000 shares of
Company common stock were reserved for issuance during 2002 resulting in total
shares reserved for issuance of 2,800,000. All outstanding options are
incentive or non-qualified, vest within three years from date of grant, and
expire 10 years from the grant date. Transactions under the Plans are
summarized as follows:
55
1997 STOCK INCENTIVE PLAN 1988 STOCK OPTION PLAN
------------------------------ ----------------------------
Weighted Average Weighted Average
Shares Exercise Price Shares Exercise Price
--------- ---------------- -------- ----------------
Outstanding at September 30, 1999 335,270 $ 18.25 422,076 $12.29
Granted 108,500 18.8125 -- --
Exercised (40,262) 18.25 (157,660) 9.65
--------- -------- -------- ------
Outstanding at September 30, 2000 403,508 18.40 264,416 13.86
Granted 137,200 27.44 -- --
Exercised (152,786) 18.30 (105,302) 13.90
--------- -------- -------- ------
Outstanding at September 30, 2001 387,922 21.64 159,114 13.84
--------- -------- -------- ------
Granted 120,340 22.63 -- --
Exercised -- -- (1,000) 18.25
--------- -------- -------- ------
Outstanding at December 31, 2001 508,262 21.87 158,114 13.81
--------- -------- -------- ------
Granted -- -- -- --
Exercised (20,379) 18.46 (22,600) 9.19
Forfeited (2,390) 24.44 -- --
--------- -------- -------- ------
Outstanding at December 31, 2002 485,493 $ 22.00 135,514 $14.58
--------- -------- -------- ------
Exercisable at September 30, 2000 158,488 $ 18.25 237,836 $13.37
Exercisable at September 30, 2001 138,068 $ 18.34 159,114 $13.84
Exercisable at December 31, 2001 249,349 $ 19.66 158,114 $13.81
Exercisable at December 31, 2002 299,619 $ 20.56 135,514 $14.58
--------- -------- -------- ------
Remaining reserved for issuance at
December 31, 2002 1,911,541 -- -- --
--------- -------- -------- ------
The following table summarizes information about options outstanding as of
December 31, 2002:
1997 STOCK INCENTIVE PLAN 1988 STOCK OPTION PLAN
- --------------------------------------------------------- -----------------------------------------------------
Weighted Average Weighted Average
Range of Exercise Remaining Contractual Range of Remaining Contractual
Prices Shares Life Exercise Prices Shares Life
- ----------------- ------- --------------------- --------------- ------- --------------------
$18.25-$18.81 230,343 5.80 years $10.06-$11.06 41,000 2.40 years
$27.44 136,300 7.83 years $15.00-$18.25 94,514 4.57 years
$22.63 118,850 8.83 years -- - --
------------- ------- ---- ------------- ------- ----
$18.25-$27.44 485,493 7.11 years $10.06-$18.25 135,514 3.91 years
============= ======= ==== ============= ======= ====
In 1992 the Company adopted the Energen Corporation 1992 Directors Stock Plan
to pay part of the compensation of its non-employee directors in shares of
Company common stock. Under the Plan, no shares were awarded during the year
ended December 31, 2002, 6,000 shares were awarded during the three-months
ended December 31, 2001 and 4,800 and 5,054 shares were awarded during the
years ended September 30, 2001 and 2000, respectively, leaving 144,639 shares
reserved for issuance as of December 31, 2002.
In 1996 the Company amended its Dividend Reinvestment and Common Stock Purchase
Plan to include a direct stock purchase feature which allows purchases by
non-shareholders. In connection with the amendment, 1,500,000 shares were added
to the Plan. As of December 31, 2002, 843,218 common shares were reserved under
this Plan.
On April 26, 2000, the Company authorized the repurchase of up to 1,000,000
shares of the Company's common stock, in addition to the 500,000 shares
authorized on May 25, 1994. For the year ended December 31, 2002 the Company
repurchased 5,319 shares, for the three-months ended December 31, 2001 the
Company repurchased 55,074 shares, and for the years ended September 30, 2001
and 2000 the Company repurchased 91,600 and 290,000 shares, respectively. As of
December 31, 2002, a total of 787,718 shares remain authorized for future
repurchase.
On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan)
designed to protect
56
shareholders from coercive or unfair takeover tactics. Under certain
circumstances, the 1998 Plan provides shareholders with the right to acquire
the Company's Series 1998 Junior Participating Preferred Stock (or, in certain
cases, securities of an acquiring person) at a significant discount. Terms and
conditions are set forth in a Rights Agreement between the Company and its
Rights Agent. Under the 1998 Plan, one right is associated with each
outstanding share of common stock. Rights outstanding under the 1998 Plan at
December 31, 2002, were convertible into 347,454 shares of Series 1998 Junior
Participating Preferred Stock (1/100 share of preferred stock for each full
right) subject to adjustment upon occurrence of certain take-over related
events. No rights were exercised or exercisable during the period. The price at
which the rights would be exercised is $70 per right, subject to adjustment
upon occurrence of certain take-over related events. In general, absent certain
take-over related events as described in the Plan, the rights may be redeemed
prior to the July 27, 2008, expiration for $0.01 per right.
In 1997 the Company adopted the 1997 Deferred Compensation Plan to allow
officers and non-employee directors to defer certain compensation. Amounts
deferred by a participant under the 1997 Deferred Compensation Plan are
credited to accounts maintained for a participant in either, a stock account or
an investment account. The stock account tracks the performance of the
Company's common stock, including reinvestment of dividends. The investment
account tracks the performance of certain mutual funds. The Company has funded,
and presently plans to continue funding, a trust in a manner that generally
tracks participants' accounts under the 1997 Deferred Compensation Plan. While
intended for payment of benefits under the 1997 Deferred Compensation Plan, the
trusts' assets remain subject to the claims of our creditors. Amounts earned
under the Deferred Compensation Plan and invested in Company common stock held
by the trust have been recorded as treasury stock, along with the related
deferred compensation obligation in the Consolidated Statements of
Shareholders' Equity.
7. COMMITMENTS AND CONTINGENCIES
- -------------------------------------------------------------------------------
CONTRACTS AND AGREEMENTS: Alagasco has various firm gas supply and firm gas
transportation contracts which expire at various dates through the year 2008.2010.
These contracts typically contain minimum demand charge obligations on the part
of Alagasco.
Alagasco entered into an agreement with a financial institution whereby it can
sell on an ongoing basis, with recourse, certain installment receivables
relatedENVIRONMENTAL MATTERS: The Company is subject to its merchandising program up to a maximum of $20 million. During
1995 and 1994, Alagasco sold $8,454,000 and $6,784,000, respectively, of
installment receivables. At September 30, 1995 and 1994, the balance of these
installment receivables was $15,618,000 and $13,027,000, respectively.
Receivables sold under this agreement are considered financial instruments with
off-balance-sheet risk. Alagasco's exposure to credit loss in the event of
non-performance by customers is represented by the balance of installment
receivables.
36
38
Various legal proceedings arising in the normal course of business are
currently in progress and Alagasco currently accrues provisions for estimated
cost. Although the outcome of any litigation cannot be predicted with
certainty, management does not believevarious environmental
regulations. Management believes that the ultimate outcome will have a
material adverse effect on Alagasco's financial position or resultsCompany is in compliance with the
currently applicable standards of operations.
8. LEASES
Total payments relatedthe environmental agencies to leases included as operating expense in the
accompanying statements of income amounted to $2,201,000, $2,147,000,which it is
subject and $2,332,000 in 1995, 1994 and 1993, respectively. Minimum future rental
payments (in thousands) required after 1995 under leases with initial or
remaining noncancelable lease terms in excess of one yearthat potential environmental liabilities are as follows:
==========================================================================================================
1996 1997 1998 1999 2000 2001 AND THEREAFTER
==========================================================================================================
$1,749 $1,577 $463 $81 $81 $125
==========================================================================================================
9. ENVIRONMENTAL MATTERSminimal. Alagasco is
in the chain of title of eight former manufactured gas plant sites, of which it
still owns four, and five manufactured gas distribution sites, of which it
still owns one. A preliminaryAn investigation of the sites does not indicate the present
need for remediation activities. Management expects that, should remediation of
any such sites be required in the future, Alagasco's share, if any, of such
costs will not materially affect the results of operations or financial
condition of Alagasco. Also, to the extent Energen Resources has operating
agreements with various joint venture partners, environmental costs would be
shared proportionately.
To date, the Company's expenditures to comply with environmental or safety
regulations have not been material and are not expected to be significant in
the future. However, new regulations, enforcement policies, claims for damages
or other events could result in significant future costs.
LEGAL MATTERS: Energen and its affiliates are, from time to time, parties to
various pending or threatened legal proceedings. Certain of these lawsuits
include claims for punitive damages in addition to other specified relief.
Based upon information presently available, and in light of available legal and
other defenses, contingent liabilities arising from threatened and pending
litigation are not considered material in relation to the respective financial
positions of Energen and its affiliates. It should be noted, however, that
Energen and its affiliates conduct business in Alabama and other jurisdictions
in which the magnitude and frequency of punitive damage awards may bear little
or no relation to culpability or actual damages, thus making it increasingly
difficult to predict litigation results.
Various legal proceedings arising in the normal course of business are in
progress currently, and the Company has accrued a provision for estimated
costs.
57
LEASE OBLIGATIONS: In January 1999 Alagasco closed on a sale-leaseback of the
Company's headquarters building. The proceeds from the sale approximated the
investment in the facility. The building is being leased back from the
purchaser over a 25-year lease term and the related lease is accounted for as
an operating lease. Under the terms of the lease, Energen has a renewal option;
the lease does not contain a bargain purchase price or a residual value
guarantee. Energen's total lease payments related to leases included as
operating lease expense, inclusive of the sale-leaseback, were $8,273,000 for
the year ended December 31, 2002, $1,837,000 for the three-months ended
December 31, 2001, $7,324,000 and $6,267,000 for the years ended September 30,
2001 and 2000, respectively. Minimum future rental payments required after 2002
under leases with initial or remaining noncancelable lease terms in excess of
one year are as follows:
Years Ending December 31, (in thousands)
- -----------------------------------------------------------------------------------------------------
2003 2004 2005 2006 2007 2008 AND THEREAFTER
- ------ ------ ------ ------ ------ -------------------
$3,609 $3,007 $2,770 $2,690 $2,412 $31,395
Alagasco's total payments related to leases included as operating expense,
inclusive of the sale-leaseback, were $2,362,000 for the year ended December
31, 2002, $587,000 for the three-months ended December 31, 2001 $2,343,000 and
$2,209,000 for the years ended September 30, 2001 and 2000, respectively.
Minimum future rental payments required after 2002 under leases with initial or
remaining noncancelable lease terms in excess of one year are as follows:
Years Ending December 31, (in thousands)
- -----------------------------------------------------------------------------------------------------
2003 2004 2005 2006 2007 2008 AND THEREAFTER
- ------ ------ ------ ------ ------ -------------------
$2,150 $1,590 $1,512 $1,504 $1,494 $22,251
8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
- -------------------------------------------------------------------------------
FINANCIAL INSTRUMENTS: The fair value of cash and cash equivalents, trade
receivables (net of allowance), and short-term debt approximates fair value due
to the short maturity of the instruments. The fair value of Energen's
fixed-rate long-term debt, including the current portion, with a carrying value
of $537,533,000, would be $570,243,000 at December 31, 2002. The fair value of
Alagasco's fixed-rate long-term debt, including the current portion, with a
carrying value of $184,533,000, would be $200,410,000 at December 31, 2002. The
fair values were based on the market value of debt with similar maturities and
current interest rates.
Alagasco entered into an agreement with a financial institution whereby it can
sell on an ongoing basis, with recourse, certain installment receivables
related to its merchandising program up to a maximum of $20 million. Alagasco
sold installment receivables of $5,010,000 in the year ended December 31, 2002,
$2,120,000 in the three-months ended December 31, 2001 and $5,444,000 and
$6,879,000 in the years ended September 30, 2001 and 2000, respectively. At
December 31, 2002 the balance of these installment receivables was $10,566,000
and represented 13,812 accounts. At December 31, 2001 and September 30, 2001,
the balance of these installment receivables was $12,838,000 and $13,249,000,
respectively. Receivables sold under this agreement are considered financial
instruments with off-balance sheet risk. Alagasco's exposure to credit loss in
the event of non-performance by customers is represented by the balance of
installment receivables.
PRICE RISK: The Company adopted SFAS No. 133 (subsequently amended by SFAS Nos.
137 and 138) on October 1, 2000. This statement requires all derivatives to be
recognized on the balance sheet and measured at fair value. If a derivative is
designated as a cash flow hedge, the Company is required to measure the
effectiveness of the hedge, or the degree that the gain (loss) for the hedging
instrument offsets the loss (gain) on the hedged item, at each reporting
period. The effective portion of the gain or loss on the derivative instrument
is recognized in other comprehensive income as a component of equity and
subsequently reclassified into earnings when the forecasted transaction affects
earnings. The ineffective portion of a derivative's change in fair value is
required to be recognized in earnings immediately. Derivatives that do not
qualify for hedge treatment under SFAS No. 133 must be recorded at fair value
with gains or losses recognized in earnings in the period of change.
58
Energen Resources periodically enters into cash flow derivative commodity
instruments to hedge its exposure to price fluctuations on oil, natural gas and
natural gas liquids production. Such instruments include regulated natural gas
and crude oil futures contracts traded on the New York Mercantile Exchange and
over-the-counter swaps, collars and basis hedges with major energy derivative
product specialists. The counterparties to the commodity instruments are
investment banks and energy-trading firms. In some contracts, the amount of
credit allowed before Energen Resources must post collateral for
out-of-the-money hedges varies depending on the credit rating of the Company's
debt. In cases where this arrangement exists, generally the Company's credit
ratings must be maintained at investment grade status to have available
counterparty credit.
Energen Resources had certain agreements with Enron North America Corp. (Enron)
as the counterparty as of October 1, 2001. As prescribed by SFAS No. 133, the
value of the outstanding Enron contracts which qualified for cash flow hedge
accounting treatment was reflected on the balance sheet as an asset and the
effective portion of the derivative was reported as other comprehensive income
(OCI), a component of shareholders' equity. These outstanding contracts ceased
to qualify as cash flow hedges during October 2001 as a result of Enron's
credit issues. The Company recorded an expense to O&M for the write-down to
fair value of the asset related to the effected derivative contracts. The
deferred revenues related to the non-performing hedges were recorded in
accumulated other comprehensive income until such time as they were
reclassified to earnings as originally forecasted to occur. As a result,
Energen's net income in the three-month transition period ended December 31,
2001, reflected a one-time, non-cash expense of $5.5 million, net of tax. Net
income in the year ended December 31, 2002, reflected a total non-cash benefit
of $5.7 million, net of tax, related to the Enron hedge position.
The Company had current losses on the fair value of derivatives of $15.9
million included in accounts payable and $1.9 million of non-current losses
included in deferred credits and other liabilities on the consolidated balance
sheet at December 31, 2002. At December 31, 2001 and September 30, 2001, the
Company had current gains on the fair value of derivatives of $3.6 million and
$22.5 million, respectively, included in prepayments and other and $3 million
and $3.2 million, respectively, of non-current gains included in deferred
charges and other.
As of December 31, 2002, $9.4 million, net of tax, of deferred net losses on
derivative instruments recorded in accumulated other comprehensive income are
expected to be reclassified to earnings during the next twelve-month period.
Gains and losses on derivative instruments that are not accounted for as cash
flow hedge transactions, as well as the ineffective portion of the change in
fair value of derivatives accounted for as cash flow hedges, are included in
operating revenues in the consolidated financial statements. The Company
recorded a $0.8 million after-tax loss in 2002 for the ineffective portion of
the change in fair value of derivatives accounted for as cash flow hedges.
Also, Energen Resources recorded an after-tax gain of $151,000 in 2002 on
contracts which did not meet the definition of cash flow hedges under SFAS No.
133. As of December 31, 2002, all of the Company's swaps and hedges met the
definition of a cash flow hedge. Subsequent to December 31, 2002, the Company
entered into a hedge contract for 150 MBbl of oil that did not meet the
definition of a cash flow hedge. The contract is considered by management to be
an economic hedge and is accounted for as a mark-to-market transaction. The
Company had $6.7 million included in current and noncurrent deferred income
taxes on the consolidated balance sheet related to other comprehensive income
as of December 31, 2002.
Energen Resources entered into the following contracts and swaps:
AVERAGE CONTRACT
PRODUCTION PERIOD TOTAL HEDGED VOLUME PRICE DESCRIPTION
- ----------------- ------------------- ----------------- ---------------------
NATURAL GAS
- ---------------------------------------------------------------------------------------------
2003 30.9 Bcf $4.13 Mcf NYMEX Swaps
4.4 Bcf $3.86 Mcf Basin Specific Swaps
4.8 Bcf $3.72 - $4.70 Mcf Basin Specific Collars
2004 6.5 Bcf $4.02 Mcf NYMEX Swaps
* 2.4 Bcf $4.42 Mcf NYMEX Swaps
* 13.9 Bcf $3.83 Mcf Basin Specific Swaps
2.4 Bcf $4.05 - $4.44 Mcf NYMEX Collars
2005 1.2 Bcf $3.75 Mcf NYMEX Swaps
59
NATURAL GAS BASIS DIFFERENTIAL
- ---------------------------------------------------------------------------------------------
2003 11.7 Bcf ** Basis Swaps
* 4.0 Bcf ** Basis Swaps
OIL
- ---------------------------------------------------------------------------------------------
2003 2,478 MBbl $26.26 Bbl NYMEX Swaps
* 150 MBbl $28.00 Bbl NYMEX Puts
2004 * 120 MBbl $26.15 Bbl NYMEX Swaps
OIL BASIS DIFFERENTIAL
- ---------------------------------------------------------------------------------------------
2003 2,174 MBbl ** Basis Swaps
* 97 MBbl ** Basis Swaps
NATURAL GAS LIQUIDS
- ---------------------------------------------------------------------------------------------
2003 38 MMGal $0.42 Gal Liquids Swaps
2004 * 30 MMGal $0.41 Gal Liquids Swaps
* Contract entered into subsequent to December 31, 2002.
** Basis average contract prices not meaningful due to the varying nature
of each contract.
All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors, which does not permit speculative
positions. The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objective and
strategy for undertaking the hedge. This process includes specific
identification of the hedging instrument and the hedge transaction, the nature
of the risk being hedged and how the hedging instrument's effectiveness in
hedging the exposure to the hedged transaction's variability in cash flows
attributable to the hedged risk will be assessed. Both at the inception of the
hedge and on an ongoing basis, the Company assesses whether the derivatives
that are used in hedging transactions are highly effective in offsetting
changes in cash flows of hedged items. The Company discontinues hedge
accounting if a derivative has ceased to be a highly effective hedge. The
maximum term over which Energen Resources has hedged exposures to the
variability of cash flows is through September 30, 2005.
On December 4, 2000, the APSC authorized Alagasco to engage in energy
risk-management activities to manage the utility's cost of gas supply. As of
December 31, 2002, Alagasco had recorded a $16,750,000 receivable in
prepayments and other representing the fair value of derivatives. As required
by SFAS No. 133, Alagasco recognizes all derivatives as either assets or
liabilities on the balance sheet. Any gains or losses are passed through to
customers using the mechanisms of the GSA in accordance with Alagasco's APSC
approved tariff.
CONCENTRATION OF CREDIT RISK: Revenues and related accounts receivable from oil
and gas operations primarily are generated from the sale of produced natural
gas and oil to natural gas and oil marketing companies. Such sales are
typically made on an unsecured credit basis with payment due during the month
following the month of delivery. This concentration of sales to the energy
marketing industry has the potential to affect the Company's overall exposure
to credit risk, either positively or negatively, in that the Company's oil and
gas purchasers may be affected similarly by changes in economic, industry or
other conditions. During 2001 and 2002, the credit rating agencies downgraded
the credit ratings of a number of energy marketers and their affiliates,
including certain oil and gas purchasers of the Company. The Company is
monitoring this situation and, in certain instances, may require credit
assurances such as a deposit, letter of credit or parent guarantee. The three
largest oil and gas purchasers buy approximately 23%, 12% and 11%,
respectively, of Energen Resources' estimated 2003 production. Energen
Resources' other purchasers each buy less than 10% of production.
Natural gas distribution operating revenues and related accounts receivable are
generated from state-regulated utility natural gas sales and transportation to
approximately 465,000 residential, commercial and industrial customers located
in central and north Alabama. A change in economic conditions may affect the
ability of customers to meet their obligations; however, the Company believes
that its provision for possible losses on uncollectible accounts receivable is
adequate for its credit loss exposure.
60
9. RECONCILIATION OF EARNINGS PER SHARE
- -------------------------------------------------------------------------------
YEAR ENDED Three Months Ended
(in thousands, except per share amounts) DECEMBER 31, 2002 December 31, 2001
--------------------------------- ---------------------------------
PER SHARE Per Share
INCOME SHARES AMOUNT Income Shares Amount
------- ------ --------- ------ ------ ---------
Basic EPS $68,639 33,605 $2.04 $3,658 31,052 $0.12
Effect of dilutive securities
Long-range performance shares 88 96
Stock options 143 127
Restricted stock 2 2
------- ------ ----- ------ ------ -----
Diluted EPS $68,639 33,838 $2.03 $3,658 31,277 $0.12
======= ====== ===== ====== ====== =====
Year Ended Year Ended
(in thousands, except per share amounts) September 30, 2001 September 30, 2000
---------------------------------- ---------------------------------
Per Share Per Share
Income Shares Amount Income Shares Amount
------- ------ --------- ------- ------ ---------
Basic EPS $67,896 30,726 $2.21 $53,018 30,108 $1.76
Effect of dilutive securities
Long-range performance shares 165 126
Stock options 187 125
Restricted stock 6 --
------- ------ ----- ------- ------ -----
Diluted EPS $67,896 31,084 $ 2.18 $53,018 30,359 $1.75
======= ====== ====== ======= ====== =====
For the year ended December 31, 2002, the Company had 136,300 options and
20,464 shares of non-vested restricted stock that were excluded from the
computation of diluted EPS, as their effect was antidilutive.
10. ASSET RETIREMENT OBLIGATIONS
- -------------------------------------------------------------------------------
The Company has adopted SFAS No. 143, "Accounting for Asset Retirement
Obligations," which requires the Company to record the fair value of a
liability for an asset retirement obligation (ARO) in the period in which it is
incurred. Upon adoption of SFAS No. 143, the Company was required to recognize
a liability for the present value of all legal obligations associated with the
retirement of tangible long-lived assets and capitalize an equal amount as a
cost of the asset as of January 1, 2002. Upon initial application of the
Statement, a cumulative effect of a change in accounting principle was also
required in order to recognize a liability for any existing AROs adjusted for
cumulative accretion, an increase to the carrying amount of the associated
long-lived asset and accumulated depreciation on the capitalized cost.
Subsequent to initial measurement, liabilities are required to be accreted to
their present value each period and capitalized costs are depreciated over the
estimated useful life of the related assets. Upon settlement of the liability,
the Company will settle the obligation for its recorded amount and will record
in resulting gain or loss.
Energen Resources recorded a liability representing expected future costs
associated with site reclamation, facilities dismantlement, and plug and
abandonment of wells as follows:
(in thousands)
Balance of ARO as of January 1, 2002 $ 20,493
Liabilities incurred during the year ended December 31, 2002 4,923
Accretion expense 1,819
--------
Balance of ARO as of December 31, 2002 $ 27,235
========
For the year ended December 31, 2002, Energen Resources recognized additional
costs of $20.1 million, depreciation expense of $1.7 million, a deferred tax
asset of $1.3 million and an after-tax charge of $2.2 million for the
cumulative effect on prior years.
61
The Company's gas distribution system operates under various property easement
agreements primarily related to public rights of way. In some instances, the
entity granting the easement retains the option to require certain actions in
the event the Company abandons the asset. Since the Company expects its gas
distribution assets will be operated in perpetuity and historical abandonment
costs resulting from such easement agreements have been de minimis, no asset
retirement obligation has been recorded.
11. SUPPLEMENTAL CASH FLOW INFORMATION
- -------------------------------------------------------------------------------
Supplemental information concerning Energen's cash flow activities is as
follows:
===========================================================================================================
FOR THEThree Months
YEAR ENDED SEPTEMBEREnded Year Ended Year Ended
DECEMBER 31, December 31, September 30, (IN THOUSANDS) 1995 1994 1993
===========================================================================================================September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- ------------
Interest paid, net of amount capitalized $11,166 $7,762 $8,726$43,085 $11,418 $42,905 $37,717
Income taxes paid $10,920 $9,097 $5,844$ 9,838 $ 4,261 $11,636 $11,885
Noncash investing activities:
First Permian, L.L.C. stock issuance $72,891 $ -- $ -- $ --
Capitalized depreciation $ 166223 $ 15551 $ 187243 $ 217
Allowance for funds used during construction $ 1,0541,336 $ 465122 $ 1632,098 $ 1,172
------- ------- ------- -------
Under SFAS No. 143, the Company recorded additional costs of $20.1 million, a
non-current liability of $27.2 million, accretion expense of $1.8 million,
depreciation expense of $1.7 million, and a deferred tax asset of $1.3 million,
all of which are non-cash adjustments concerning Energen's cash flow activities
for the year ended December 31, 2002.
Supplemental information concerning Alagasco's cash flow activities is as
follows:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Interest paid, net of amount capitalized $14,012 $5,666 $12,154 $ 9,787
Income taxes paid $15,519 $9,425 $18,318 $15,833
Noncash financing activities (debt issuance costs)investing activities:
Capitalized depreciation $ 340223 $ 33051 $ 243 $ 217
Allowance for funds used during construction $ 1,336 $ 122 $ 2,098 $ 1,172
------- ------ ------- -------
12. LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS
- -------------------------------------------------------------------------------
On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This statement retains the
previous asset impairment requirements of SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
for loss recognition when the carrying value of an asset exceeds the sum of the
undiscounted estimated future cash flow of the asset. In addition, SFAS No. 144
requires that gains and losses in the sale of certain oil and gas properties
and write-downs of certain properties held-for-sale be reported as discontinued
operations, with income or loss from operations of the associated properties
reported as income or loss from discontinued operations. All assets
held-for-sale must be reported at the lower of the carrying amount or fair
value. Accordingly, during the second quarter of 2002, Energen Resources
recorded a pre-tax writedown of $2.8 million on certain non-strategic gas
properties located in the Gulf Coast region, adjusting the carrying amount of
the properties to their fair value based upon expected future discounted cash
flows. In November 2002, the Company sold these properties for approximately
the carrying amount. The gain on disposals for the year ended December 31,
2002, included a total of $3.7 million largely due to sales of property located
in the Permian Basin. As of December 31, 2002, the Company had no properties
classified as held-for-sale.
62
In 2001 and 2000, a pre-tax gain of $0.8 million and $1.1 million,
respectively, was recorded in operating revenues from continuing operations for
certain non-strategic property sales. In the third fiscal quarter of 2000, as a
result of a downward reserve revision in a small oil and gas field, Energen
Resources recorded a pre-tax write-down of $3.5 million in additional
depreciation, depletion and amortization expense, adjusting the carrying amount
of the properties to their fair value based on expected future discounted cash
flows.
The following are the results of operations from discontinued operations:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands, except per share data) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Oil and gas revenues $ 1,744 $1,164 $7,599 $4,186
------- ------ ------ ------
Pretax income (loss) from
discontinued operations $ (438) $ 138 $2,974 $ 790
Income tax expense (benefit) (171) 59 1,165 307
------- ------ ------ ------
INCOME (LOSS) FROM DISCONTINUED OPERATIONS (267) 79 1,809 483
------- ------ ------ ------
Impairment charge on held-for-sale property (2,815) -- -- --
(Loss) gain on disposal 3,700 -- -- --
Income tax expense (benefit) 345 -- -- --
------- ------ ------ ------
GAIN ON DISPOSAL 540 -- -- --
------- ------ ------ ------
TOTAL INCOME (LOSS) FROM
DISCONTINUED OPERATIONS $ 273 $ 79 $1,809 $ 483
======= ====== ====== ======
DILUTED EARNINGS PER AVERAGE COMMON SHARE
Income (Loss) from Discontinued Operations $ (0.01) $ -- ===========================================================================================================$ 0.05 $ 0.02
Gain on Disposal 0.02 -- -- --
------- ------ ------ ------
Total Income from Discontinued Operations $ 0.01 $ -- $ 0.05 $ 0.02
======= ====== ====== ======
BASIC EARNINGS PER AVERAGE COMMON SHARE
Income (Loss ) from Discontinued Operations $ (0.01) $ -- $ 0.05 $ 0.02
Gain on Disposal 0.02 -- -- --
------- ------ ------ ------
Total Income from Discontinued Operations $ 0.01 $ -- $ 0.05 $ 0.02
======= ====== ====== ======
37
39
11.13. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
- -------------------------------------------------------------------------------
The following data summarizesummarizes quarterly operating results forresults. The Company's
business is seasonal in character and strongly influenced by weather
conditions.
Year Ended December 31, 2002
--------------------------------------------------------------------
(in thousands, except per share amounts) First Second Third Fourth
----------- ----------- ----------- -----------
Operating revenues $ 244,383 $ 138,464 $ 116,952 $ 177,376
Operating income $ 61,022 $ 25,721 $ 13,187 $ 36,156
Income from continuing operations before cumulative
effect of change in accounting principle $ 39,038 $ 12,611 $ 124 $ 18,813
Net income $ 36,682 $ 12,744 $ 127 $ 19,086
Diluted earnings per average common share
Continuing operations $ 1.24 $ 0.37 $ 0.00 $ 0.54
Net income $ 1.17 $ 0.37 $ 0.00 $ 0.55
Basic earnings per average common share
Continuing operations $ 1.25 $ 0.37 $ 0.00 $ 0.54
Net income $ 1.18 $ 0.37 $ 0.00 $ 0.55
----------- ----------- ----------- -----------
63
Year Ended September 30, 2001
--------------------------------------------------------------------
(in thousands, except per share amounts) First Second Third Fourth
----------- ----------- ----------- -----------
Operating revenues $ 173,988 $ 331,440 $ 159,894 $ 112,052
Operating income $ 26,725 $ 67,931 $ 22,740 $ 3,639
Income (loss) from continuing operations before
cumulative effect of change in accounting principle $ 13,115 $ 46,503 $ 10,013 $ (3,555)
Net income (loss) $ 13,719 $ 46,992 $ 10,373 $ (3,188)
Diluted earnings (loss) per average common share
Continuing operations $ 0.42 $ 1.50 $ 0.32 $ (0.11)
Net income (loss) $ 0.44 $ 1.52 $ 0.33 $ (0.10)
Basic earnings (loss) per average common share
Continuing operations $ 0.43 $ 1.52 $ 0.32 $ (0.11)
Net income (loss) $ 0.45 $ 1.53 $ 0.34 $ (0.10)
----------- ----------- ----------- -----------
The summarized quarterly information above has been revised to reflect the
four quartersadoption of 1995SFAS No. 143, (see Note 10) and 1994.SFAS No. 144, (see Note 12) as of
January 1, 2002.
The following data summarizes quarterly operating results. Alagasco's business
is seasonal in character and strongly influenced by weather conditions.
============================================================================================================
1995 FISCAL QUARTERS
(IN THOUSANDS) FIRST SECOND THIRD FOURTH
============================================================================================================Year Ended December 31, 2002
--------------------------------------------------------------
(in thousands, except per share amounts) First Second Third Fourth
-------- ------- -------- --------
Operating revenues $67,226 $134,141 $55,865 $38,735$196,524 $75,709 $ 50,225 $101,973
Operating income (loss) $ 3,69652,811 $ 19,2764,721 $ 3,383 $(1,924)(8,907) $ 10,745
Net income (loss) available for common $ 1,75130,542 $ 17,267964 $ 1,772 $(5,069)
============================================================================================================(7,700) $ 3,758
-------- ------- -------- --------
============================================================================================================
1994 FISCAL QUARTERS
(IN THOUSANDS) FIRST SECOND THIRD FOURTH
============================================================================================================Year Ended September 30, 2001
--------------------------------------------------------------
(in thousands, except per share amounts) First Second Third Fourth
-------- ------- -------- --------
Operating revenues $78,993 $158,268 $66,070 $41,306$119,126 $270,286 $103,779 $ 60,671
Operating income (loss) $ 2,9456,498 $ 18,48530,176 $ 3,580 $(2,711)3,186 $ (3,020)
Net income (loss) available$ 4,040 $ 27,333 $ 578 $ (5,936)
-------- ------- -------- --------
14. ACQUISITION OF OIL AND GAS PROPERTIES
- -------------------------------------------------------------------------------
On April 8, 2002, Energen Resources completed its purchase of oil and gas
properties located in the Permian Basin in west Texas from First Permian,
L.L.C. (First Permian), for approximately $120 million cash and 3,043,479
shares of the Company's common stock. The common stock was valued at $23.95 per
share, the average stock price at the time Energen signed the related Purchase
and Sale Agreement. The total acquisition approximated $184 million; this
estimate reflects an effective date of January 1, 2002, with appropriate
purchase price adjustments from that date forward until completion of the
transaction, resulting from interim cash flows and related tax items.
Summarized below are the consolidated results of operations for the year ended
December 31, 2002, the three months ended December 31, 2001 and the year ended
September 30, 2001, on an unaudited pro forma basis as if the acquisition had
occurred at the beginning of each period presented. The pro form information is
based on our consolidated results of operations for the year ended December 31,
2002, the three months ended December 31, 2001 and the year ended September 30,
2001, and on the data provided by the acquired companies, after giving effect
to the issuance of 3,043,479 million shares of common stock. The pro forma
financial information does not purport to be indicative of results of
operations that would have occurred had the transaction occurred on the basis
assumed above nor are they indicative of results of the future operations of
the combined enterprises.
64
Three Months
YEAR ENDED Ended Year Ended
Unaudited DECEMBER 31, December 31, September 30,
(in thousands, except per share amounts) 2002 2001 2001
------------ ------------ -------------
Operating revenues $683,780 $153,938 $802,187
Net income $ 69,772 $ 4,387 $ 66,562
Diluted earnings per average common share $ 6962.06 $ 16,6880.14 $ 1,799 $(4,287)
===========================================================================================================2.14
Basic earnings per average common share $ 2.08 $ 0.14 $ 2.17
======== ======== ========
12.15. REGULATORY ASSETS AND LIABILITES
The following table details regulatory asset and liabilities amounts on the
consolidated balance sheets:
DECEMBER 31, 2002 December 31, 2001 September 30, 2001
Energen Corporation -------------------------- ------------------------ --------------------
(in thousands) CURRENT NONCURRENT Current Noncurrent Current Noncurrent
------- ---------- ------- ---------- ------- ----------
Regulatory assets:
Pension asset $ -- $14,744 $ -- $ -- $ -- $ --
Early retirement costs -- -- -- -- 95 --
------- ------- ------ ---- ------ ----
Total regulatory assets $ -- $14,744 $ -- $ -- $ 95 $ --
======= ======= ====== ==== ====== ====
Regulatory liabilities:
Enhanced stability reserve $ 2,963 $ -- $2,702 $ -- $2,686 $ --
Gas supply adjustment 20,851 -- 5,760 -- 1,106 --
Deferred income taxes -- 1,468 -- 137 -- 242
------- ------- ------ ---- ------ ----
Total regulatory liabilities $23,814 $ 1,468 $8,462 $137 $3,792 $242
======= ======= ====== ==== ====== ====
16. TRANSACTIONS WITH RELATED PARTIES
Alagasco purchased natural gas from affiliates amounting to $4,644,000,
$10,255,000,$1,820,000 for the
year ended December 31, 2002, $375,000 for the three-months ended December 31,
2001, $5,254,000 and $13,826,000, in 1995, 1994,$3,662,000, for the years ended September 30, 2001 and
1993,2000, respectively. These amounts are included in gas purchased for resale.
Alagasco had net payables to affiliates of $1,432,000 and $3,054,000 at December
31, 2002 and December 31, 2001, net receivables from affiliates of $183,000$937,000 at
September 30, 1995,2001 and net payables to affiliates of $132,000$1,156,000 at September 30,
1994.
13.2000.
17. OTHER INCOME AND EXPENSE
The following table details Energen's other income and expense amounts on the
consolidated income statements:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Allowance for funds used during construction $ 1,336 $ 122 $ 2,098 $ 1,172
Merchandise revenues 14,155 4,226 14,535 15,885
Other 153 6 192 258
------- ------ ------- -------
Total other income $15,644 $4,354 $16,825 $17,315
======= ====== ======= =======
Cost of goods sold $10,215 $3,181 $10,136 $10,777
Other merchandise expense 4,888 1,204 4,756 4,763
------- ------ ------- -------
Total other expense $15,103 $4,385 $14,892 $15,540
======= ====== ======= =======
65
The following table details Alagasco's other income and expense amounts on the
income statements:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Merchandise revenues $5,520 $1,596 $5,978 $7,520
------ ------ ------ ------
Total other income $5,520 $1,596 $5,978 $7,520
====== ====== ====== ======
Cost of goods sold $2,702 $ 946 $3,051 $3,564
Other merchandise expense 3,578 892 3,534 3,675
------ ------ ------ ------
Total other expense $6,280 $1,838 $6,585 $7,239
====== ====== ====== ======
18. RECENT PRONOUNCEMENTS OF THE FINANCIAL INSTRUMENTSACCOUNTING STANDARDS BOARD (FASB)
In accordanceJuly 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," which requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred. The
Company adopted this statement as of January 1, 2002 (See Note 10).
The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or
Disposal Activities" in June 2002. This statement requires that a liability for
costs associated with exit or disposal activities be recognized at fair value in
the period the liability is incurred. This Statement does not apply to costs
associated with the retirement of long-lived assets covered by SFAS No. 143. The
Company has adopted this statement for disposal or exit activities initiated
after December 31, 2002.
The FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure" in December 2002. This statement is effective for
2003 and amends SFAS No. 123, "Accounting for Stock-Based Compensation" by
providing alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation. In
addition, SFAS No. 148 requires additional disclosures related to the effect of
stock-based compensation on reported results. The Company has adopted the
disclosure provisions of SFAS No. 148 and is currently reviewing its treatment
of stock-based compensation as well as the impact of this pronouncement.
The FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosures
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others," (FIN 45) in November 2002. FIN 45 clarifies the requirements of SFAS
No. 107 (Disclosures about Fair
Value5, "Accounting for Contingencies," related to a guarantors accounting for,
and disclosures of, the issuance of certain types of guarantees. Management has
completed a review of potential contingencies and noted the following guarantee
disclosure: Alagasco has an agreement with a financial institution whereby it
can sell on an ongoing basis, with recourse, certain installment receivables
related to its merchandising program up to a maximum of $20 million. Alagasco's
exposure to credit loss in the event of non-performance by customers is
represented by the balance of installment receivables (see Note 8). The Company
is required to adopt the provisions for initial recognition and measurement for
all guarantees issued or modified after December 31, 2002 on a prospective
basis. The Company is currently reviewing the impact related to the initial
recognition and measurement guarantees of this Interpretation.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46) which clarifies the application of
Accounting Research Bulletin No. 51, "Consolidated Financial Instruments)Statements." This
Interpretation provides guidance on the identification and consolidation of
variable interest entities (VIEs), whereby control is achieved through means
other than through voting rights. Management has completed an analysis of FIN 46
and has determined that the estimated fair valuesCompany does not have VIEs.
66
19. OIL AND GAS OPERATIONS (UNAUDITED)
The following schedules detail historical financial data of Alagasco's
financial instruments at September 30, 1995, werethe Company's oil
and gas operations. Certain terms appearing in the schedules are prescribed by
the Securities and Exchange Commission (SEC) and are briefly described as
follows:
EXPLORATION EXPENSES are costs primarily associated with drilling unsuccessful
exploratory wells in undeveloped properties, exploratory geological and
geophysical activities, and costs of impaired and expired leaseholds.
DEVELOPMENT COSTS include costs necessary to gain access to, prepare and equip
development wells in areas of proved reserves.
PRODUCTION (LIFTING) COSTS include costs incurred to operate and maintain wells.
GROSS REVENUES are reported after deduction of royalty interest payments.
GROSS WELL OR ACRE is a well or acre in which a working interest is owned.
NET WELL OR ACRE is deemed to exist when the sum of fractional ownership working
interests in gross wells or acres equals one.
DRY WELL is an exploratory or a development well found to be incapable of
producing either oil or gas in sufficient quantities to justify completion as an
oil or gas well.
PRODUCTIVE WELL is an exploratory or a development well that is not a dry well.
CAPITALIZED COSTS
==============================================================================================================
CARRYING FAIR
AS OF SEPTEMBERDECEMBER 31, December 31, September 30, 1995 (IN THOUSANDS) AMOUNT VALUE
==============================================================================================================September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Cash
Proved $1,091,536 $841,155 $818,535 $707,236
Unproved 11,936 3,807 4,421 6,530
---------- -------- -------- --------
Total capitalized costs 1,103,472 844,962 822,956 713,766
Accumulated depreciation, depletion, and
amortization 269,616 228,867 209,451 165,447
---------- -------- -------- --------
Capitalized costs, net $ 833,856 $616,095 $613,505 $548,319
========== ======== ======== ========
COSTS INCURRED: The following table sets forth costs incurred in property
acquisition, exploration and development activities and includes both
capitalized costs and costs charged to expense during the year:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Property acquisition:
Proved $173,984 $ 238 $ 33,764 $ 2,086
Unproved 10,193 81 552 350
Exploration 527 339 1,734 1,472
Development 122,494 24,757 103,574 66,717
-------- ------- -------- -------
Total costs incurred $307,198 $25,415 $139,624 $70,625
======== ======= ======== =======
67
RESULTS OF CONTINUING OPERATIONS: The following table sets forth results of the
Company's oil and gas continuing operations:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Gross revenues $254,021 $53,145 $223,150 $184,415
Production (lifting costs) 80,333 16,630 77,796 62,028
Exploration expense* 3,602 827 4,226 4,890
Depreciation, depletion and amortization** 69,990 16,020 52,502 55,114
Income tax expense 23,929 4,035 18,232 8,298
-------- ------- -------- --------
Results of continuing operation from producing
activities $ 76,167 $15,633 $ 70,394 $ 54,085
======== ======= ======== ========
* Includes a $3.2 million pre-tax writedown in the year ended December
31, 2002, a $0.7 million pre-tax writedown in the three-months ended
December 31, 2001, and a $2.7 million and $3.8 million pre-tax
writedown in the years ended September 30, 2001 and 2000, respectively,
of a portion of an unproved leasehold
** Includes a pre-tax writedown of $3.5 million in the year ended
September 30, 2000 under SFAS No. 121 (see Note 12)
AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE FROM CONTINUING
OPERATIONS
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
2002 2001 2001 2000
------------ ------------ ------------- -------------
Average sales price including the effects of hedging:
Gas (Mcf) $ 3.16 $ 2.97 $ 3.09 $ 2.49
Oil (per barrel) $24.03 $24.19 $23.78 $18.33
Natural gas liquids (per barrel) $12.75 $10.07 $17.61 $16.06
Average sales price excluding the effects of hedging:
Gas (Mcf) $ 2.96 $ 2.35 $ 4.86 $ 3.06
Oil (per barrel) $24.75 $19.79 $27.46 $26.45
Natural gas liquids (per barrel) $12.75 $10.07 $17.61 $16.06
Average production (lifting) cost (per Mcfe) $ 1.04 $ 0.94 $ 1.16 $ 0.90
Average production tax (per Mcfe) $ 0.24 $ 0.20 $ 0.36 $ 0.25
Average depreciation rate (per Mcfe)* $ 0.90 $ 0.91 $ 0.79 $ 0.75
====== ====== ====== ======
* Excludes a pre-tax writedown of $3.5 million in the year ended
September 30, 2000 under SFAS No. 121 (see Note 12)
DRILLING ACTIVITY: The following table sets forth the total number of net
productive and dry exploratory and development wells drilled:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
2002 2001 2001 2000
------------ ------------ ------------- -------------
Exploratory:
Productive 0.1 0.3 0.1 0.3
Dry 0.1 -- 1.3 --
----- ---- ---- ----
Total 0.2 0.3 1.4 0.3
===== ==== ==== ====
Development:
Productive 145.9 23.8 90.7 70.6
Dry 4.3 -- -- 1.5
----- ---- ---- ----
Total 150.2 23.8 90.7 72.1
===== ==== ==== ====
68
As of December 31, 2002, the Company was participating in the drilling of 6
gross development wells, with the Company's interest equivalent to 3.31 wells.
PRODUCTIVE WELLS AND ACREAGE: The following table sets forth the total gross and
net productive gas and oil wells as of December 31, 2002, and developed and
undeveloped acreage as of the latest practicable date prior to year-end:
Gross Net
------- -------
Gas Wells 3,426 1,725
Oil Wells 2,785 1,069
------- -------
Developed Acreage 772,519 428,080
Undeveloped Acreage 121,871 53,428
------- -------
There were 42 wells with multiple completions in 2002. All wells and acreage are
located onshore in the United States, with the majority of the net undeveloped
acreage located in the Permian Basin.
OIL AND GAS OPERATIONS: The calculation of proved reserves is made pursuant to
rules prescribed by the SEC. Such rules, in part, require that only proved
categories of reserves be disclosed and that reserves and associated values be
calculated using year-end prices and current costs. Changes to prices and costs
could have a significant effect on the disclosed amount of reserves and their
associated values. In addition, the estimation of reserves inherently requires
the use of geologic and engineering estimates which are subject to revision as
reservoirs are produced and developed and as additional information is
available. Accordingly, the amount of actual future production may vary
significantly from the amount of reserves disclosed. The proved reserves are
located onshore in the United States of America.
Year ended December 31, 2002 Gas MMcf Oil MBbl NGL MBbl
- ---------------------------- -------- ------- -------
Proved reserves at beginning of period 714,395 19,128 25,944
Revisions of previous estimates (3,916) (1,303) 624
Purchases 6,263 36,779 --
Discoveries and other additions 141,435 1,367 2,030
Production (48,051) (3,193) (1,794)
Sales (6,378) (2,945) (107)
-------- ------- -------
Proved reserves at end of period 803,748 49,833 26,697
-------- ------- -------
Proved developed reserves at end of period 672,633 36,782 24,009
======== ======= =======
Three months ended December 31, 2001 Gas MMcf Oil MBbl NGL MBbl
- ------------------------------------ -------- ------- -------
Proved reserves at beginning of period 627,051 20,878 24,931
Revisions of previous estimates 89,055 (1,038) 1,381
Purchases 1 27 2
Discoveries and other additions 10,805 43 154
Production (12,018) (550) (451)
Sales (499) (232) (73)
-------- ------- -------
Proved reserves at end of period 714,395 19,128 25,944
-------- ------- -------
Proved developed reserves at end of period 646,202 16,293 23,476
======== ======= =======
Year ended September 30, 2001 Gas MMcf Oil MBbl NGL MBbl
- ----------------------------- -------- ------- -------
Proved reserves at beginning of period 777,456 24,518 26,007
Revisions of previous estimates (134,543) (2,407) (2,006)
Purchases 9,334 1,100 836
Discoveries and other additions 26,145 1,995 1,672
Production (46,463) (2,187) (1,482)
Sales (4,878) (2,141) (96)
-------- ------- -------
Proved reserves at end of period 627,051 20,878 24,931
-------- ------- -------
Proved developed reserves at end of period 579,991 17,467 22,867
======== ======= =======
69
Year ended September 30, 2000 Gas MMcf Oil MBbl NGL MBbl
- ----------------------------- -------- ------- -------
Proved reserves at beginning of period 740,001 24,719 21,937
Revisions of previous estimates 37,028 (2,601) 3,250
Purchases 1,819 1,997 308
Discoveries and other additions 47,146 2,890 1,942
Production (48,084) (2,304) (1,429)
Sales (454) (183) (1)
------ ------ ----
Proved reserves at end of period 777,456 24,518 26,007
------ ------ ----
Proved developed reserves at end of period 691,287 18,714 22,906
======= ====== ======
During 2002, Energen Resources invested approximately $174 million in proved
property acquisitions. Energen Resources sold approximately 25 Bcfe of proved
reserves, recording net pre-tax gains of $4 million.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES: The standardized measure of discounted future net cash flows
is not intended, nor should it be interpreted, to present the fair market value
of the Company's crude oil and natural gas reserves. An estimate of fair market
value would take into consideration factors such as, but not limited to, the
recovery of reserves not presently classified as proved reserves, anticipated
future changes in prices and costs, and a discount factor more representative of
the time value of money and the risks inherent in reserve estimates. At December
31, 2002, December 31, 2001, and September 30, 2001 and 2000, the Company had a
deferred hedging loss of $17.2 million, a deferred hedging gain of $15.2 million
and $25.7 million and a deferred hedging loss of $89.4 million, respectively,
all of which are excluded from the calculation of standardized measure of future
net cash flows.
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ----------- ------------- -------------
Future gross revenues $5,455,802 $2,181,148 $1,672,436 $4,824,681
Future production costs 1,754,700 829,968 693,817 1,379,913
Future development costs 183,818 114,317 83,781 110,660
---------- ---------- ---------- ----------
Future net cash equivalentsflows before income taxes 3,517,284 1,236,863 894,838 3,334,108
Future income tax expense 1,100,392 265,611 124,803 1,073,051
---------- ---------- ---------- ----------
Future net cash flows after income taxes 2,416,892 971,252 770,035 2,261,057
Discount at 10% per annum 1,172,635 399,810 272,493 1,155,792
---------- ---------- ---------- ----------
Standardized measure of discounted future net
cash flows relating to proved oil and gas
reserves $1,244,257 $ 727571,442 $ 727
Receivables,497,542 $1,105,265
========== ========== ========== ==========
Reserves and associated values were calculated using year-end prices and current
costs. The following are the principal sources of changes in the standardized
measure of discounted future net cash flows:
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Balance at beginning of year $ 571,442 $ 497,542 $ 1,105,265 $ 613,854
----------- --------- ----------- -----------
Revisions to reserves proved in prior years:
Net changes in prices, production costs and
future development costs 658,956 100,710 (1,015,900) 715,746
Net changes due to revisions in quantity
estimates (8,380) 49,579 (81,076) 37,049
Development costs incurred, previously
estimated 49,418 8,812 50,768 39,589
Accretion of discount 57,144 11,398 144,266 61,385
Other (8,669) (24,012) 95,165 6,850
----------- --------- ----------- -----------
70
Total revisions 748,469 146,487 (806,777) 860,619
New field discoveries and extensions, net of
allowance accountfuture production and development costs 213,625 5,562 33,685 110,727
Sales of oil and gas produced, net of production
costs (162,151) (23,699) (220,220) (157,533)
Purchases 218,799 20 32,811 17,657
Sales (14,203) (2,271) (26,256) (1,110)
Net change in income taxes (331,724) (52,199) 379,034 (338,949)
----------- --------- ----------- -----------
Net change in standardized measure of
discounted future net cash flows 672,815 73,900 (607,723) 491,411
----------- --------- ----------- -----------
Balance at end of year $ 23,359 $23,359
Long-term debt (including current maturities) $100,000 $98,750
==============================================================================================================1,244,257 $ 571,442 $ 497,542 $ 1,105,265
=========== ========= =========== ===========
71
20. INDUSTRY SEGMENT INFORMATION
- -------------------------------------------------------------------------------
The following methodsCompany is principally engaged in two business segments: the acquisition,
development, exploration and assumptions were used to estimateproduction of oil and gas in the fair valuecontinental
United States (oil and gas operations) and the purchase, distribution and sale
of financial instruments:
o CASH AND CASH EQUIVALENTS: Fair value was considered to benatural gas in central and north Alabama (natural gas distribution). The
accounting policies of the segments are the same as those described in Note 1.
Certain reclassifications have been made to conform the carrying amount.
o RECEIVABLES: The Company believes that, in the aggregate, current and
non-current net receivables were not materially different from the fair
value of those receivables.
o LONG-TERM DEBT: The fair value of fixed-rate long-term debt was based on
the market value of debt with similar maturities and with interest rates
currently trading in the marketplace; the carrying amount of variable rate
long-term debt was assumed to approximate fair value.
38
40
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS OF ENERGEN CORPORATION:
Our report on the consolidatedprior years' financial
statements of Energen Corporation and
subsidiaries has been incorporated by reference in this Form 10-K from page 55
of the 1995 Annual Report to Stockholders of Energen Corporation and
subsidiaries. In connection with our audits of such financial statements, we
have also audited the related financial statement schedules listed in the index
on page 17 and 18 of this Form 10-K.
In our opinion, the financial statement schedules referred to above, when
considered in relation to the basic financial statements taken as a whole,
present fairly, in all material respects the information required to be
included therein.
Coopers & Lybrand L.L.P.
Birmingham, Alabama
October 25, 1995
39current year presentation.
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Operating revenues from continuing operations
Oil and gas operations $ 252,744 $ 49,486 $ 223,512 $ 185,248
Natural gas distribution 424,431 96,678 553,862 366,161
----------- ----------- ----------- -----------
Total $ 677,175 $ 146,164 $ 777,374 $ 551,409
=========== =========== =========== ===========
Operating income (loss) from continuing operations
Oil and gas operations $ 78,416 $ 3,243 $ 72,425 $ 47,568
Natural gas distribution 59,370 8,034 50,288 49,063
Eliminations and corporate expenses (1,700) (417) (1,678) (1,620)
----------- ----------- ----------- -----------
Total $ 136,086 $ 10,860 $ 121,035 $ 95,011
=========== =========== =========== ===========
Depreciation, depletion and amortization
expense from continuing operations
Oil and gas operations $ 71,405 $ 16,351 $ 53,846 $ 56,226
Natural gas distribution 33,682 8,151 30,933 28,708
----------- ----------- ----------- -----------
Total $ 105,087 $ 24,502 $ 84,779 $ 84,934
=========== =========== =========== ===========
Interest expense
Oil and gas operations $ 29,635 $ 7,042 $ 30,244 $ 28,441
Natural gas distribution 14,557 3,680 12,316 9,870
Eliminations and other (479) (88) (490) (542)
----------- ----------- ----------- -----------
Total $ 43,713 $ 10,634 $ 42,070 $ 37,769
=========== =========== =========== ===========
Income tax expense (benefit) from continuing operations
Oil and gas operations $ 3,941 $ (4,843) $ 1,728 $ (7,552)
Natural gas distribution 17,825 1,547 13,448 14,324
Other (1,257) (88) (365) (290)
----------- ----------- ----------- -----------
Total $ 20,509 $ (3,384) $ 14,811 $ 6,482
=========== =========== =========== ===========
Capital expenditures
Oil and gas operations $ 305,476 $ 25,052 $ 136,886 $ 67,090
Natural gas distribution 65,815 12,873 56,090 67,073
Other 5 -- 60 287
----------- ----------- ----------- -----------
Total $ 371,296 $ 37,925 $ 193,036 $ 134,450
=========== =========== =========== ===========
Identifiable assets
Oil and gas operations $ 926,839 $ 687,776 $ 716,043 $ 737,814
Natural gas distribution 603,209 549,221 516,802 471,282
Eliminations and other 843 3,359 (8,966) (6,055)
----------- ----------- ----------- -----------
Total $ 1,530,891 $ 1,240,356 $ 1,223,879 $ 1,203,041
=========== =========== =========== ===========
Property, plant and equipment, net
Oil and gas operations $ 838,526 $ 620,305 $ 617,592 $ 552,287
Natural gas distribution 418,098 385,137 380,489 355,248
Other 179 237 253 294
----------- ----------- ----------- -----------
Total $ 1,256,803 $ 1,005,679 $ 998,334 $ 907,829
=========== =========== =========== ===========
72
41
SCHEDULE II --- VALUATION AND QUALIFYING ACCOUNTS
ENERGEN CORPORATION AND SUBSIDIARIES
====================================================================================================
YEARSENERGEN CORPORATION
Three Months
YEAR ENDED SEPTEMBEREnded Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(IN THOUSANDS) 1995 1994 1993
====================================================================================================2002 2001 2001 2000
------------ ------------- ------------- -------------
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year $2,037 $1,927 $1,927
- ----------------------------------------------------------------------------------------------------BALANCE AT BEGINNING OF YEAR $ 11,783 $ 10,031 $ 6,681 $ 5,598
-------- -------- -------- -------
Additions:
Charged to income: 2,431 1,825 1,656income 5,482 1,819 7,953 4,287
Recoveries and adjustments 67 153 81
- ----------------------------------------------------------------------------------------------------
2,498 1,978 1,737
- ----------------------------------------------------------------------------------------------------(495) 139 (901) (276)
-------- -------- -------- -------
Net additions 4,987 1,958 7,052 4,011
-------- -------- -------- -------
Less uncollectible accounts written off 2,002 1,868 1,737
- ----------------------------------------------------------------------------------------------------(7,896) (206) (3,702) (2,928)
-------- -------- -------- -------
BALANCE AT END OF YEAR $2,533 $2,037 $1,927
====================================================================================================$ 8,874 $ 11,783 $ 10,031 $ 6,681
======== ======== ======== =======
40
42
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
ALABAMA GAS CORPORATION
====================================================================================================
YEARSThree Months
YEAR ENDED SEPTEMBEREnded Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(IN THOUSANDS) 1995 1994 1993
====================================================================================================2002 2001 2001 2000
------------ ------------- ------------- -------------
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year $2,000 $1,800 $1,800
- ----------------------------------------------------------------------------------------------------BALANCE AT BEGINNING OF YEAR $ 11,100 $ 9,500 $ 5,800 $ 4,532
-------- -------- ------- -------
Additions:
Charged to income: 1,935 1,805 1,613income 5,410 1,816 7,799 4,275
Recoveries and adjustments 67 263 78
- ----------------------------------------------------------------------------------------------------
2,002 2,068 1,691
- ----------------------------------------------------------------------------------------------------(565) (38) (452) (276)
-------- -------- ------- -------
Net additions 4,845 1,778 7,347 3,999
-------- -------- ------- -------
Less uncollectible accounts written off 2,002 1,868 1,691
- ----------------------------------------------------------------------------------------------------(7,745) (178) (3,647) (2,731)
-------- -------- ------- -------
BALANCE AT END OF YEAR $2,000 $2,000 $1,800
====================================================================================================$ 8,200 $ 11,100 $ 9,500 $ 5,800
======== ======== ======= =======
41ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
73
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Information regarding the executive officers of Energen is included in Part I.
The other information required by Item 10 is incorporated herein by reference
from Energen's definitive proxy statement for the Annual Meeting of
Shareholders to be held April 23, 2003. The proxy statement will be filed on or
about March 20, 2003.
ITEM 11. EXECUTIVE COMPENSATION
The information regarding executive compensation is incorporated herein by
reference from Energen's definitive proxy statement for the Annual Meeting of
Shareholders to be held April 23, 2003.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
A. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The information regarding the security ownership of the beneficial
owners of more than five percent of Energen's common stock is
incorporated herein by reference from Energen's definitive proxy
statement for the Annual Meeting of Shareholders to be held April 23,
2003.
B. SECURITY OWNERSHIP OF MANAGEMENT
The information regarding the security ownership of management is
incorporated herein by reference from Energen's definitive proxy
statement for the Annual Meeting of Shareholders to be held April 23,
2003.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related transactions is
incorporated herein by reference from Energen's definitive proxy statement for
the Annual Meeting of Shareholders to be held April 23, 2003.
74
PART IV
ITEM 14. CONTROLS AND PROCEDURES
A. Our chief executive officer and chief financial officer, have evaluated
the effectiveness of our disclosure controls and procedures as of a date within
90 days before the filing of this report. Based on that evaluation they have
concluded that our disclosure controls and procedures are effective.
B. Our chief executive officer and chief financial officer have concluded
that there were no significant changes in our internal controls or in other
factors that could significantly affect those controls subsequent to the date of
their most recent evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
A. DOCUMENTS FILED AS PART OF THIS REPORT
(1) FINANCIAL STATEMENTS
The consolidated financial statements of Energen and the financial
statements of Alagasco are included in Item 8 of this Form 10-K
(2) FINANCIAL STATEMENT SCHEDULES
The financial statement schedules are included in Item 8 of this Form
10-K
(3) EXHIBITS
The exhibits listed on the accompanying Index to Exhibits are filed as
part of this Form 10-K
B. REPORTS ON FORM 8-K
Form 8-K dated March 14, 2002, reporting that Energen Resources signed
a Purchase and Sale Agreement with First Permian, L.L.C.
Form 8-K dated April 10, 2002, reporting that Energen Resources
completed its purchase of oil and gas properties from First Permian,
L.L.C.
Form 8-K dated June 4, 2002, reporting that Alagasco had filed a
request with the Alabama Public Service Commission (APSC) to continue
its rate-setting methodology, Rate Stabilization and Equalization (RSE)
Form 8-K dated June 11, 2002, reporting that the APSC extended
Alagasco's rate-setting methodology, RSE for a six-year period through
January 1, 2008
Form 8-K dated July 24, 2002, commenting on the Company's financial
relationships with Williams Companies Inc. and Dynegy, Inc.
Form 8-K dated August 14, 2002, reporting the certification which
accompanied the Form 10-Q for the quarterly period ended June 30, 2002,
pursuant to 18 United States Code section 1350, as enacted by section
906 of the Sarbanes-Oxley Act of 2002
75
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO EXHIBITS
ITEM 14(A)(3)
Exhibit
Number Description
- ------- ------------
*3(a) Restated Certificate of Incorporation of Energen Corporation (composite, as amended February 2, 1998) which was
filed as Exhibit 3(a) to Energen's Annual Report on Form 10-K for the year ended September 30, 1998 (File No.
1-7810)
*3(b) Articles of Amendment to Restated Certificate of Incorporation of Energen, designating Series 1998 Junior
Participating Preferred Stock (July 27, 1998) which was filed as Exhibit 4(b) to Energen's Post Effective Amendment
No. 1 to Registration Statement on Form S-3 (Registration No. 333-00395)
*3(c) Bylaws of Energen Corporation (as amended through July 22, 1998) which was filed as Exhibit 3(c) to Energen's
Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810)
*3(d) Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated September
27, 1995, which was filed as Exhibit 3(i) to the Registrant's Annual Report on Form 10-K for the year ended
September 30, 1995 (file No. 1-7810)
*3(e) Bylaws of Alabama Gas Corporation (as amended through July 22, 1998) which was filed as Exhibit 3(e) to Energen's
Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810)
*4(a) Rights Agreement, dated as of July 27, 1998, between Energen Corporation and First Chicago Trust Company of New
York, Rights Agent, which was filed as Exhibit 1 to Energen's Registration Statement on Form 8-A, dated July 10,
1998 (File No. 1-7810)
*4(b) Form of Indenture between Energen Corporation and The Bank of New York, as Trustee, which was dated as of September
1, 1996 (the "Energen 1996 Indenture"), and which was filed as Exhibit 4(i) to the Registrant's Registration
Statement on Form S-3 (Registration No. 333-11239)
*4(b)(i) Officers' Certificate, dated September 13, 1996, pursuant to Section 301 of the Energen 1996 Indenture setting
forth the terms of the Series A Notes which was filed as Exhibit 4(d)(i) to Energen's Annual Report on Form 10-K
for the year ended September 30, 2001 (File No. 1-7810)
*4(b)(ii) Officers' Certificate, dated July 8, 1997, pursuant to Section 301 of the Energen 1996 Indenture amending the terms
of the Series A Notes which was filed as Exhibit 4(d)(ii) to Energen's Annual Report on Form 10-K for the year
ended September 30, 2001 (File No. 1-7810)
*4(b)(iii) Amended and Restated Officers' Certificate, dated February 27, 1998, setting forth the terms of the Series B Notes
which was filed as Exhibit 4(d)(iii) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001
(File No. 1-7810)
*4(d) Indenture dated as of November 1, 1993, between Alabama Gas Corporation and NationsBank of Georgia, National
Association, Trustee, ("Alagasco 1993 Indenture"), which was filed as Exhibit 4(k) to Alabama Gas' Registration
Statement on Form S-3 (Registration No. 33-70466)
*4(d)(i) Officers' Certificate, dated August 30, 2001, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth
the terms of the 6.25 percent Notes due September 1, 2016, which was filed as Exhibit 4.01 to Alabama Gas' Current
Report on Form 8-K filed September 27, 2001
76
*4(d)(ii) Officers' Certificate, dated August 30, 2001, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth
the terms of the 6.75 percent Notes due September 1, 2031, which was filed as Exhibit 4.02 to Alabama Gas' Current
Report on Form 8-K filed September 27, 2001
*10(a) Form of Service Agreement Under Rate Schedule CSS (No. S10710), between Southern Natural Gas Company and Alabama
Gas Corporation which was filed as Exhibit 10(a) to Energen's Annual Report on Form 10-K for the year ended
September 30, 1993 (File No. 1-7810)
*10(b) Form of Service Agreement Under Rate Schedule FT-NN (No. 866941), between Southern Natural Gas Company and Alabama
Gas Corporation which was filed as Exhibit 10(c) to Energen's Annual Report on Form 10-K for the year ended
September 30, 1993 (File No. 1-7810)
*10(c) Form of Executive Retirement Supplement Agreement between Energen Corporation and it's executive officers (as
revised October 2000) which was filed as Exhibit 10(c) to Energen's Annual Report on Form 10-K for the year ended
September 30, 2000 (File No. 1-7810)
*10(d) Form of Addendum to Executive Retirement Supplement Agreement between Energen Corporation and it's executive
officers which was filed as Exhibit 10(d) to Energen's Annual Report on Form 10-K for the year ended September 30,
2000 (File No. 1-7810)
*10(e) Form of Severance Compensation Agreement between Energen Corporation and it's executive officers which was filed as
Exhibit 10(d) to Energen's Annual Report on Form 10-K for the year ended September 30, 1999 (File No. 1-7810)
*10(f) Energen Corporation 1988 Stock Option Plan (as amended November 25, 1997) which was filed as Exhibit 10(e) to
Energen's Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810)
*10(g) Energen Corporation 1992 Long-Range Performance Share Plan (as amended effective October 1, 1999) which was filed
as Exhibit 10(f) to Energen's Annual Report on Form 10-K for the year ended September 30, 1999 (File No. 1-7810)
*10(h) Energen Corporation 1997 Stock Incentive Plan (as amended effective October 1, 2001) which was filed as Exhibit
10(h) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810)
*10(i) Energen Corporation 1997 Deferred Compensation Plan (as amended effective October 1, 1999) which was filed as
Exhibit 10(h) to Energen's Annual Report on Form 10-K for the year ended September 30, 1999 (File No. 1-7810)
*10(j) Energen Corporation 1992 Directors Stock Plan (as amended April 25, 1997) which was filed as Exhibit 10(i) to
Energen's Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810)
*10(k) Energen Corporation Annual Incentive Compensation Plan, as amended effective October 1, 2001 which was filed as
Exhibit 10(k) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810)
*10(l) Energen Corporation Officer Split Dollar Life Insurance Plan, effective October 1, 1999 which was filed as Exhibit
10(l) to Energen's Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810)
77
*10(m) Form of Split Dollar Life Insurance Plan Agreement under Energen Corporation Officer Split Dollar Life Insurance
Plan which was filed as Exhibit 10(m) to Energen's Annual Report on Form 10-K for the year ended September 30, 2000
(File No. 1-7810)
*10(n) Officer Split Dollar Tax Matters Agreement which was filed as Exhibit 10(n) to Energen's Annual Report on Form 10-K
for the year ended September 30, 2000 (File No. 1-7810)
21 Subsidiaries of Energen Corporation
23 Consent of Independent Accountants (Energen Corporation)
*Incorporated by reference
78
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrants have duly caused this report to be signed
on their behalf by the undersigned thereunto duly authorized.
ENERGEN CORPORATION
(Registrant)
ALABAMA GAS CORPORATION
(Registrant)
March 18, 2003 By /s/ Wm. Michael Warren, Jr.
- ---------------------- ----------------------------------------
Wm. Michael Warren, Jr.
Chairman, President and Chief Executive
Officer of Energen, Chairman and Chief
Executive Officer of Alabama Gas
Corporation
79
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed by the following persons on behalf of the Registrants and
in the capacities and on the dates indicated:
March 18, 2003 By /s/ Wm. Michael Warren, Jr.
- -------------------------------- --------------------------------------------------
Wm. Michael Warren, Jr.
Chairman, President and Chief Executive Officer of
Energen, Chairman and Chief Executive Officer of
Alabama Gas Corporation
March 18, 2003 By /s/ Geoffrey C. Ketcham
- -------------------------------- --------------------------------------------------
Geoffrey C. Ketcham
Executive Vice President, Chief Financial Officer and
Treasurer of Energen and Alabama Gas Corporation
March 18, 2003 By /s/ Grace B. Carr
- -------------------------------- --------------------------------------------------
Grace B. Carr
Vice President and Controller of Energen
March 18, 2003 By /s/ Paula H. Rushing
- -------------------------------- --------------------------------------------------
Paula H. Rushing
Vice President-Finance of Alabama Gas
Corporation
March 18, 2003 By /s/ Julian W. Banton
- -------------------------------- --------------------------------------------------
Julian W. Banton
Director
March 18, 2003 By /s/ J. Mason Davis, Jr.
- -------------------------------- --------------------------------------------------
J. Mason Davis, Jr.
Director
March 18, 2003 By /s/ James S. M. French
- -------------------------------- --------------------------------------------------
James S. M. French
Director
March 18, 2003 By /s/ T. Michael Goodrich
- -------------------------------- --------------------------------------------------
T. Michael Goodrich
Director
March 18, 2003 By /s/ Judy M. Merritt
- -------------------------------- --------------------------------------------------
Judy M. Merritt
Director
80
CERTIFICATION
- -------------
I, Wm. Michael Warren, Jr., certify that:
1. I have reviewed this report on Form 10-K of Energen Corporation and
Alabama Gas Corporation;
2. Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this report.
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this report (the "Evaluation Date"); and
c) presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weakness in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
March 18, 2003 By /s/ Wm. Michael Warren, Jr.
- ------------------ -----------------------------------------
Wm. Michael Warren, Jr.
Chairman, President and Chief Executive
Officer of Energen Corporation, Chairman
and Chief Executive Officer of Alabama
Gas Corporation
81
CERTIFICATION
- -------------
I, G. C. Ketcham, certify that:
1. I have reviewed this report on Form 10-K of Energen Corporation and
Alabama Gas Corporation;
2. Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this report.
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this report (the "Evaluation Date"); and
c) presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weakness in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
March 18, 2003 By /s/ G. C. Ketcham
- ------------------ ------------------------------------
G. C. Ketcham
Executive Vice President, Chief
Financial Officer and Treasurer of
Energen Corporation and Alabama Gas
Corporation
82