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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2003
|_| 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 ALABAMA 63-0757759
2-38960 ALABAMA GAS CORPORATION ALABAMA 63-0022000
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 filers 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. |_|
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). YES |X| NO |_|
Aggregate market value of the voting stock held by non-affiliates of the
registrants as of June 30 2003:
Energen Corporation $1,160,436,680
Indicate number of shares outstanding of each of the registrant's classes of
common stock as of March 4, 2004:
Energen Corporation 36,346,358 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
Energen Corporation Proxy Statement to be filed on or about March 29, 2004 (Part
III, Item 10-13)
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 derivative 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
reduce 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 anticipated 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 stratigraphic
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 reducing 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 detected 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
RESERVES (PUD) expected 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- PRODUCTION Ratio expressing years of supply determined by
RATIO dividing the remaining recoverable reserves at
year end by actual annual production volumes.
SECONDARY RECOVERY The process of injecting water, gas, etc., into 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
thousand cubic feet per barrel.
ENERGEN CORPORATION
2003 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
PAGE
----
PART I
Item 1. Business...................................................................................... 3
Item 2. Properties.................................................................................... 9
Item 3. Legal Proceedings............................................................................. 9
Item 4. Submission of Matters to a Vote of Security Holders........................................... 9
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters......................... 11
Item 6. Selected Financial Data....................................................................... 12
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations......... 14
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.................................... 29
Item 8. Financial Statements and Supplementary Data................................................... 30
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure.......................................................................... 77
Item 9A. Controls and Procedures....................................................................... 77
PART III
Item 10. Directors and Executive Officers of the Registrants........................................... 78
Item 11. Executive Compensation........................................................................ 78
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters................................................................... 78
Item 13. Certain Relationships and Related Transactions................................................ 78
Item 14. Principal Accountant Fees and Services........................................................ 78
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.............................. 79
Signatures .............................................................................................. 83
2
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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 FACTORS: 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, the Company's oil and gas subsidiary, 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 and cash flows;
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, based in Birmingham, Alabama, is a diversified energy
holding company engaged primarily in the acquisition, development, exploration
and production of oil, natural gas and 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 oldest 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 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.
4
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 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, 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. The Company's Web site also
includes its Code of Ethics, Corporate Governance Guidelines, Audit Committee
Charter, Officers' Review Committee Charter, Governance and Nominations
Committee Charter and Finance Committee Charter.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The information required by this item is provided in Note 21, Industry Segment
Information, in the Notes to Financial Statements.
NARRATIVE DESCRIPTION OF BUSINESS
- - 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, 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 2003, Energen Resources' inventory of proved oil and gas
reserves totaled 1,364.9 billion cubic feet equivalent (Bcfe).
Substantially all of the company's approximately 1.4 trillion cubic feet
equivalent of reserves are located in the San Juan Basin in New Mexico,
the Permian Basin in west Texas, the Black Warrior Basin in Alabama, and
the north Louisiana/east Texas region. Approximately 81 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 65 percent of Energen
Resources' proved reserves, with oil representing approximately 23 percent
and natural gas liquids comprising the balance.
GROWTH STRATEGY: Energen has operated for more than eight years under a
strategy to grow its oil and gas operations. Since the end of fiscal year
1995, Energen Resources has invested approximately $755 million in
property acquisitions, $555 million in related development, and $90
million in exploration and related development. Energen Resources' capital
investment for oil and gas activities over the five-year period ending
December 31, 2008, is currently expected to approximate $1.4 billion, the
majority of which represents unidentified acquisitions and related
development.
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 with varying characteristics 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
5
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
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 2000, the Company's development efforts have
added approximately 357 Bcfe of proved reserves from the drilling of
approximately 749 gross development wells and 406 well recompletions and
pay-adds. In 2003, Energen Resources' successful development wells and
other activities added approximately 135 Bcfe of proved reserves. The
company drilled 347 gross development wells, performed some 145 well
recompletions and pay-adds, and conducted other operational enhancements.
Energen Resources' production from continuing operations totaled 85.4 Bcfe
in 2003 and is estimated to total 85 Bcfe in 2004, including 81.6 Bcfe of
estimated production from proved reserves owned at December 31, 2003.
RISK MANAGEMENT: Energen Resources attempts to lower the risks 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 the then-current oil and gas futures
prices in its evaluation models, 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 estimated annual production in
any given year depending on its pricing outlook.
Statement of Financial Accounting Standards (SFAS) No. 133 (as amended),
"Accounting for Derivative Instruments and Hedging Activities," 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
operating revenues when the forecasted transaction affects earnings. The
ineffective portion of a derivative's change in fair value is required to
be recognized in operating revenues immediately. Derivatives that do not
qualify for hedge treatment under SFAS No. 133 must be recorded at fair
value with gains or losses recognized as operating revenues in earnings in
the period of change under mark-to-market accounting.
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. To the extent that Energen Resources has
operating agreements with various joint venture partners, environmental
costs would be shared proportionately.
RISK FACTORS: 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.
6
- - NATURAL GAS DISTRIBUTION
GENERAL: Alagasco 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, using
Alagasco as their agent or acting on their own, purchase gas directly from
producers, marketers or suppliers and arrange for delivery of the gas into
the Alagasco distribution system. Alagasco charges a fee to transport such
customer-owned gas through its distribution system to the customers'
facilities.
Alagasco's service territory is located in central and parts of north
Alabama and includes approximately 185 cities and communities in 28
counties. The aggregate population of the counties served by Alagasco is
estimated to be 2.4 million. Among the cities served by Alagasco are
Birmingham, the center of the largest metropolitan area in Alabama, and
Montgomery, the state capital. During 2003, Alagasco served an average of
427,413 residential customers and 35,463 commercial, industrial and
transportation customers. The Alagasco distribution system includes
approximately 9,810 miles of main and more than 11,494 miles of service
lines, odorization and regulation facilities, and customer meters.
APSC REGULATION: As an Alabama utility, Alagasco is subject to regulation
by the Alabama Public Service Commission (APSC) which, in 1983,
established the Rate Stabilization and Equalization (RSE) rate-setting
process. RSE was extended in 2002, 1996, 1990, 1987 and 1985. On June 10,
2002, the APSC extended RSE for a six-year period, through January 1,
2008. Under the APSC order, Alagasco's allowed range of return on average
equity remains 13.15 percent to 13.65 percent 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, the APSC conducts quarterly reviews to determine, based on
Alagasco's projections and year-to-date performance, whether Alagasco's
return on average equity at the end of the rate year will be within the
allowed range. Reductions in rates can be made quarterly to bring the
projected return within the allowed range; increases, however, are allowed
only once each rate 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 Alagasco's
operations and maintenance (O&M) expense. Under 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 points above or
below the percentage change in the Consumer Price Index For All Urban
Consumers (index range), no adjustment is required. If the change in O&M
expense per customer exceeds the index range, three-quarters of the
difference is returned to customers. To the extent the change is less than
the index range, the utility benefits by one-half of the difference
through future rate adjustments.
The temperature adjustment rider to Alagasco's rate tariff, approved by
the APSC in 1990, was designed to mitigate the earnings impact of
variances from normal temperatures. Alagasco calculates a temperature
adjustment to customers' monthly bills to substantially remove the effect
of departures from normal temperatures on Alagasco's earnings. This
adjustment, however, is subject to certain limitations including
regulatory limits on adjustments to increase customers' bills, the impact
of non-temperature weather conditions such as wind velocity or cloud cover
and the impact of any elasticity of demand as a result of high commodity
prices. 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.
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 a
7
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 provides for accretions to the ESR in an amount of no more than
$40,000 monthly until the maximum funding level is achieved.
GAS SUPPLY: Alagasco's distribution system is connected to two major
interstate natural gas pipeline systems - Southern Natural Gas Company
(Southern) and Transcontinental Gas Pipe Line Company (Transco). It is
also connected to several intrastate natural gas pipeline systems and to
Alagasco's two liquified natural gas (LNG) facilities.
Alagasco purchases natural gas from various natural gas producers and
marketers. Certain volumes are purchased under firm contractual
commitments with other volumes purchased on a spot market basis. The
purchased volumes are delivered to Alagasco's system using a variety of
firm transportation, interruptible transportation and storage capacity
arrangements designed to meet the system's varying levels of demand.
Alagasco's LNG facilities can provide the system with up to 200,000
additional thousand cubic feet per day (Mcfd) of natural gas to meet peak
day demand.
As of December 31, 2003, Alagasco had the following contracts in place for
firm natural gas pipeline transportation and storage services:
--------------------------------------------------------------------------
DECEMBER 31, 2003
--------------------------------------------------------------------------
(Mcfd)
-----------------
Southern firm transportation 164,332
Southern storage and no notice transportation 251,679
Transco firm transportation 100,000
Various intrastate transportation 23,900
--------------------------------------------------------------------------
COMPETITION AND RATE FLEXIBILITY: The price of natural gas is a
significant competitive factor in Alagasco's service territory,
particularly among large commercial and industrial transportation
customers. Propane, coal and fuel oil are readily available, and many
industrial customers have the capability to switch to alternate fuels
and/or alternate sources of gas. In the residential and small commercial
and industrial markets, electricity is the principal competitor. With the
support of the APSC, Alagasco has implemented a variety of flexible rate
strategies to help it compete for the large customer gas load in the
deregulated marketplace. Rate flexibility remains critical as the utility
faces competition for this 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 under 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 decrease gas costs for its
residential and small commercial and industrial customers. In 2003,
approximately 300 of Alagasco's transportation customers utilized the P
Rate, and the resulting reduction in core market gas costs totaled
approximately $7.5 million.
The Competitive Fuel Clause (CFC) and Transportation Tariff also have been
important to Alagasco's ability to compete effectively for customer load
in its service territory. The CFC allows Alagasco to adjust large customer
rates on a case-by-case basis to compete with alternate fuels and
alternate sources of gas. The GSA rider to Alagasco's tariff allows the
Company to recover the reduction in charges 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 costs. The Transportation Tariff allows
Alagasco to transport gas for customers, rather than buy and resell it to
them, and is based on Alagasco's sales profit margin so that operating
margins are unaffected. During 2003 substantially all of Alagasco's large
commercial and industrial customer deliveries were the transportation of
customer-owned gas. In addition, Alagasco served as
8
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 2003, 50 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, given its
mature, slow-growth service area. In 2003, Alagasco's average number of
customers increased slightly. For 2004, 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 continues to be
Alagasco's municipal acquisition program. Since 1985, Alagasco has
acquired 23 municipally owned systems adding more than 43,000 customers
through initial system purchases and subsequent customer additions.
Approximately 75 municipal systems remain in Alabama. Alagasco continues
to pursue the purchase of municipal gas systems, and company management
believes that such acquisitions could offer future growth opportunities.
SEASONALITY: Alagasco's gas distribution business is highly seasonal since
a material portion of the utility's total sales and delivery volumes is to
space heating customers. Alagasco's rate tariff includes a temperature
adjustment rider primarily for residential, small commercial and small
industrial customers which substantially 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 and five manufactured gas distribution sites.
It still owns four 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 of any associated
costs will not materially affect the Company's results of its operations
or financial condition.
RISK FACTORS: For a discussion of risks inherent in the Company's
businesses, see Management's Discussion and Analysis of Financial
Condition and Results of Operations as set forth in Item 7 of Part II of
this Form 10-K.
EMPLOYEES
The Company has 1,500 employees; Alagasco employs 1,232 and Energen Resources
employs 268. The Company believes that its relations with employees are good.
9
ITEM 2. PROPERTIES
The corporate headquarters of Energen, Alagasco and Energen 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 and
reserves is summarized in the table below and included in Note 20, Oil and Gas
Operations (unaudited), included in the Form 10-K in the Notes to Financial
Statements.
- --------------------------------------------------------------------------------
YEAR ENDED
DECEMBER 31, 2003 DECEMBER 31, 2003
- --------------------------------------------------------------------------------
Production Volumes Proved Reserves
(MMcfe) (MMcfe)
---------------------------------------
San Juan Basin 28,406 666,349
Permian Basin 31,263 365,394
Black Warrior Basin 15,549 252,416
North Louisiana/East Texas 10,087 75,004
Other 852 5,782
- --------------------------------------------------------------------------------
Total 86,157 1,364,945
- --------------------------------------------------------------------------------
The properties of Alagasco consist primarily of its gas distribution system,
which includes more than 9,810 miles of main, more than 11,494 miles of service
lines, odorization and regulation facilities, and customer meters. Alagasco also
has two LNG facilities, seven division offices, four payment centers, four
district offices, nine service centers, and other related property and
equipment, some of which are leased by Alagasco. For a further description of
Alagasco's properties, see the discussion under Item 1-Business.
ITEM 3. LEGAL PROCEEDINGS
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 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 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 difficult to 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 2003.
10
EXECUTIVE OFFICERS OF THE REGISTRANTS
ENERGEN CORPORATION
Name Age Position (1)
- ---- --- ------------
Wm. Michael Warren, Jr. 56 Chairman of the Board
President and Chief Executive Officer (2)
Geoffrey C. Ketcham 53 Executive Vice President, Chief Financial
Officer and Treasurer (3)
James T. McManus 45 President and Chief Operating Officer of
Energen Resources (4)
Dudley C. Reynolds 51 President and Chief Operating Officer of
Alagasco (5)
Grace B. Carr 48 Vice President and Controller (6)
J. David Woodruff, Jr. 47 General Counsel and Secretary and Vice
President-Corporate Development (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 the Board of Directors.
(2) Mr. Warren has been employed by the Company in various
capacities since 1983. In January 1992 he was elected
President and Chief Operating Officer of Energen and all of
its subsidiaries, in October 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. Mr.
Warren serves as a Director of Energen and each of its
subsidiaries. He is also a Director of Protective Life
Corporation.
(3) Mr. Ketcham has been employed by the Company in various
financial and strategic 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.
(4) Mr. McManus has been employed by the Company in various
capacities since 1986. He was elected Executive Vice President
and Chief Operating Officer of Energen Resources in October
1995 and President of Energen Resources in April 1997.
(5) Mr. Reynolds has been employed by the Company in various
capacities since 1980. He was elected General Counsel and
Secretary of Energen and each of its subsidiaries in April
1991. He was elected President and Chief Operating Officer of
Alagasco effective January 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 in January 1998 and elected Vice President and
Controller of Energen in October 2001.
(7) Mr. Woodruff has been employed by the Company in various
capacities since 1986. He was elected Vice President-Legal and
Assistant Secretary of Energen and each of its subsidiaries in
April 1991 and Vice President-Corporate Development of Energen
in October 1995. He was elected General Counsel and Secretary
of Energen and each of its subsidiaries effective January 1,
2003.
11
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE
- --------------------------------------------------------------------------------
Quarter ended (in dollars) HIGH LOW CLOSE DIVIDENDS PAID
- --------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------
March 31, 2003 32.06 28.08 32.06 .180
June 30, 2003 34.29 31.60 33.30 .180
September 30, 2003 37.09 31.35 36.18 .185
December 31, 2003 42.00 36.14 41.03 .185
- --------------------------------------------------------------------------------
Energen's common stock is listed on the New York Stock Exchange under the symbol
EGN. On February 9, 2004, there were approximately 7,750 holders of record of
Energen's common stock. 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 to Weighted Number of Securities Remaining
be Issued Upon Exercise Average Available for Future Issuance
Plan Category of Outstanding Options Exercise Price Under Equity Compensation Plans
- --------------------------------------------------------------------------------------------------------------
Equity compensation plans
approved by security holders 588,420 $22.28 1,744,823
Equity compensation plans not
approved by security holders -- -- --
- --------------------------------------------------------------------------------------------------------------
Total 588,420 $22.28 1,744,823
- --------------------------------------------------------------------------------------------------------------
12
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data as set forth below should be read in conjunction
with the Consolidated Financial Statements and the Notes to Financial Statements
included in this Form 10-K.
SELECTED FINANCIAL AND COMMON STOCK DATA
ENERGEN CORPORATION
- -----------------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended Year Ended Year Ended Year Ended
(dollars in thousands, except DECEMBER 31, December 31, December 31, September 30, September 30, September 30, September 30,
per share amounts) 2003 2002 2001* 2001 2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT
Operating revenues $ 842,221 $ 668,551 $ 143,632 $ 762,816 $ 542,012 $ 487,654 $ 492,847
Income from continuing
operations before
cumulative effect of change
in accounting principle $ 110,265 $ 70,396 $ 3,730 $ 62,417 $ 51,488 $ 41,729 $ 32,535
Net income $ 110,654 $ 68,639 $ 3,658 $ 67,896 $ 53,018 $ 41,410 $ 36,249
Diluted earnings per average
common share from
continuing operations
before cumulative effect of
change in accounting
principle $ 3.09 $ 2.08 $ 0.12 $ 2.01 $ 1.70 $ 1.39 $ 1.11
Diluted earnings per average
common share $ 3.10 $ 2.03 $ 0.12 $ 2.18 $ 1.75 $ 1.38 $ 1.23
- -----------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET
Capitalization at year-end:
Common shareholders'
equity $ 699,032 $ 582,810 $ 474,205 $ 480,767 $ 400,860 $ 361,504 $ 329,249
Long-term debt 552,842 512,954 544,133 544,110 353,932 371,824 372,782
- -----------------------------------------------------------------------------------------------------------------------------------
Total capitalization $1,251,874 $1,095,764 $1,018,338 $1,024,877 $ 754,792 $ 733,328 $ 702,031
- -----------------------------------------------------------------------------------------------------------------------------------
Total assets $1,781,432 $1,643,012 $1,342,346 $1,313,885 $1,286,341 $1,261,469 $1,064,142
- -----------------------------------------------------------------------------------------------------------------------------------
Property, plant and
equipment, net $1,433,451 $1,351,554 $1,093,201 $1,084,052 $ 986,604 $ 933,333 $ 822,741
- -----------------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA
Annual dividend rate at
period-end $ 0.74 $ 0.72 $ 0.70 $ 0.70 $ 0.68 $ 0.66 $ 0.64
Cash dividends paid per
common share $ 0.73 $ 0.71 $ 0.175 $ 0.685 $ 0.665 $ 0.645 $ 0.625
Book value per common share $ 19.30 $ 16.77 $ 15.18 $ 15.45 $ 13.21 $ 12.09 $ 11.23
Market-to-book ratio at
period-end (%) 213 174 162 145 225 167 169
Yield at period-end (%) 1.8 2.5 2.8 3.1 2.3 3.3 3.4
Return on average common
equity (%) 17.1 12.4 13.0 15.8 13.7 11.7 11.1
Price-to-earnings (diluted)
ratio at period-end 13.2 14.3 -- 10.3 17.0 14.7 15.4
Shares outstanding at
period-end (000) 36,224 34,745 31,249 31,125 30,351 29,904 29,327
Price Range:
High $ 42.00 $ 29.99 $ 25.20 $ 40.25 $ 30.38 $ 20.38 $ 22.50
Low $ 28.08 $ 21.65 $ 21.50 $ 21.50 $ 14.69 $ 13.13 $ 15.13
Close $ 41.03 $ 29.10 $ 24.65 $ 22.50 $ 29.75 $ 20.25 $ 19.00
- -----------------------------------------------------------------------------------------------------------------------------------
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
13
SELECTED BUSINESS SEGMENT DATA
Energen Corporation
- -----------------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended Year Ended Year Ended Year Ended
DECEMBER 31, December 31, December 31, September 30, September 30, September 30, September 30,
(dollars in thousands) 2003 2002 2001* 2001 2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
OIL AND GAS OPERATIONS
Operating revenues from
continuing operations
Natural gas $ 235,649 $ 145,935 $ 34,290 $ 132,554 $ 113,168 $ 113,219 $ 89,866
Oil 87,200 72,758 11,128 43,880 36,143 33,779 19,508
Natural gas liquids 25,890 21,857 4,282 24,540 21,443 6,683 6,482
Other 4,383 3,570 (2,746) 7,980 5,097 8,419 7,051
- -----------------------------------------------------------------------------------------------------------------------------------
Total $ 353,122 $ 244,120 $ 46,954 $ 208,954 $ 175,851 $ 162,100 $ 122,907
- -----------------------------------------------------------------------------------------------------------------------------------
Production volumes from
continuing operations
Natural gas (MMcf) 55,433 46,060 11,454 44,071 45,557 51,105 40,631
Oil (MBbl) 3,412 3,016 464 1,873 1,983 2,823 1,298
Natural gas liquids
(MBbl) 1,587 1,712 428 1,397 1,334 700 760
- -----------------------------------------------------------------------------------------------------------------------------------
Production volumes from
continuing operations
(MMcfe) 85,422 74,424 16,801 63,690 65,459 72,243 52,979
- -----------------------------------------------------------------------------------------------------------------------------------
Total production volumes
(MMcfe) 86,157 77,973 18,022 68,478 70,482 77,159 57,353
- -----------------------------------------------------------------------------------------------------------------------------------
Proved reserves
Natural gas (MMcf) 886,307 803,748 714,395 627,051 777,456 740,001 542,039
Oil (MBbl) 52,528 49,833 19,128 20,878 24,518 24,719 19,845
Natural gas liquids
(MBbl) 27,245 26,697 25,944 24,931 26,007 21,937 17,292
- -----------------------------------------------------------------------------------------------------------------------------------
Total (MMcfe) 1,364,945 1,262,928 984,827 901,905 1,080,605 1,019,937 764,861
- -----------------------------------------------------------------------------------------------------------------------------------
Other data from continuing
operations
Lease operating expense
(LOE)
LOE and other $ 67,920 $ 57,141 $ 11,474 $ 49,273 $ 49,866 $ 53,441 $ 37,918
Production taxes 27,731 18,254 3,387 22,833 16,536 10,677 8,688
- -----------------------------------------------------------------------------------------------------------------------------------
Total $ 95,651 $ 75,395 $ 14,861 $ 72,106 $ 66,402 $ 64,118 $ 46,606
- -----------------------------------------------------------------------------------------------------------------------------------
Depreciation and
amortization $ 79,687 $ 68,009 $ 15,317 $ 50,907 $ 53,499 $ 57,402 $ 52,194
Capital expenditures $ 163,338 $ 305,476 $ 25,052 $ 136,886 $ 67,090 $ 198,577 $ 120,991
Operating income $ 155,481 $ 78,105 $ 3,496 $ 66,416 $ 45,853 $ 31,541 $ 16,643
- -----------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS DISTRIBUTION
- -----------------------------------------------------------------------------------------------------------------------------------
Operating revenues
Residential $ 320,938 $ 277,088 $ 63,724 $ 367,109 $ 233,839 $ 209,263 $ 241,964
Commercial and
industrial-small 126,638 104,247 22,445 147,636 88,521 77,254 89,361
Transportation 38,250 38,395 9,765 33,972 35,312 34,541 35,246
Other 3,273 4,701 744 5,145 8,489 4,496 3,369
- -----------------------------------------------------------------------------------------------------------------------------------
Total $ 489,099 $ 424,431 $ 96,678 $ 553,862 $ 366,161 $ 325,554 $ 369,940
- -----------------------------------------------------------------------------------------------------------------------------------
Gas delivery volumes (MMcf)
Residential 27,248 26,358 5,128 31,064 26,069 24,751 31,079
Commercial and
industrial-small 12,564 11,838 2,193 14,054 12,092 11,662 13,705
Transportation 55,623 59,644 12,973 53,989 70,534 66,356 70,563
- -----------------------------------------------------------------------------------------------------------------------------------
Total 95,435 97,840 20,294 99,107 108,695 102,769 115,347
- -----------------------------------------------------------------------------------------------------------------------------------
Average number of customers
Residential 427,413 425,630 422,461 428,663 429,368 425,937 423,602
Commercial, industrial
and transportation 35,463 35,601 35,161 35,882 35,526 35,111 34,782
- -----------------------------------------------------------------------------------------------------------------------------------
Total 462,876 461,231 457,622 464,545 464,894 461,048 458,384
- -----------------------------------------------------------------------------------------------------------------------------------
Other data
Depreciation and
amortization $ 37,171 $ 33,682 $ 8,151 $ 30,933 $ 28,708 $ 26,730 $ 25,153
Capital expenditures $ 57,906 $ 65,815 $ 12,873 $ 56,090 $ 67,073 $ 46,029 $ 54,168
Operating income $ 66,848 $ 59,370 $ 8,034 $ 50,288 $ 49,063 $ 46,565 $ 41,663
- -----------------------------------------------------------------------------------------------------------------------------------
14
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
CRITICAL 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 judgments and estimates by the 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.
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. Estimates of physical quantities of oil and gas reserves have
been determined by Company engineers. Independent oil and gas reservoir
engineers have reviewed the estimates of proved reserves of natural gas, oil and
natural gas liquids that the Company has attributed to its net interests in oil
and gas properties as of December 31, 2003. The independent reservoir engineers
have issued reports covering approximately 97 percent of the Company's ending
proved reserves indicating that in their judgment the estimates are reasonable
in the aggregate. The Company's production of undeveloped reserves requires 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
properties can result in a revision to 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 expense or due to an immediate writedown of the
property's book value if an impairment is warranted. The table below reflects
the estimated increase (decrease) in 2004 depreciation and depletion expense
associated with changes in oil and gas reserve quantities from the reported
amounts at December 31, 2003.
- -------------------------------------------------------------------------------------------------
Percentage Change in Oil & Gas Reserves
From Reported Reserves as of December 31, 2003
(dollars in thousands) +10% +5% -5% -10%
- -------------------------------------------------------------------------------------------------
Estimated change in depreciation expense for
the year ended December 31, 2004, net of tax $(3,900) $(2,000) $ 2,400 $ 5,000
- -------------------------------------------------------------------------------------------------
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. 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.
15
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 impact on the Company's need for impairment or on 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.
DERIVATIVES: Energen Resources periodically enters into commodity derivative
contracts to manage its exposure to oil, natural gas and natural gas liquids
price volatility. Statement of Financial Accounting Standard (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (as amended)
requires all derivatives to be recognized on the balance sheet and measured at
fair value. Realized gains and losses from derivatives designated as cash flow
hedges are recognized in oil and gas production revenues when the forecasted
transaction occurs. Energen Resources periodically enters into derivative
transactions that do not qualify for cash flow hedge accounting but are
considered by management to be valid economic hedges. SFAS No. 133 requires that
gains and losses from the change in fair value of derivative instruments that do
not qualify for hedge accounting be reported in current period operating
revenues, rather than in the period in which the hedge transaction is settled.
Energen Resources does not enter into derivatives or other financial instruments
for trading purposes. SFAS No. 133 is subject to interpretations in its
application. The potential exists for additional issues to be brought under
review, and, if subsequent interpretations of SFAS No. 133 are different than
current interpretations, it is possible that the Company's policy, as stated
above, may be modified.
NATURAL GAS DISTRIBUTION
REGULATED OPERATIONS: Alagasco applies Statement of Financial Accounting
Standard (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 PENSION PLANS: Determining the Company's obligations to employees under
its defined benefit pension plans requires the use of estimates. The calculation
of the liability related to the Company's defined benefit pension plans 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. The discount rate used for actuarial purposes covering a
majority of employees was 6 percent for the year ended December 31, 2003. A
hypothetical 25 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. The return on
assets used for actuarial purposes was 9 percent for the year ended December 31,
2003. A hypothetical 25 basis point change in the return on assets would impact
total pension expense by approximately $245,000. The discount rate and return on
plan assets used in the actuarial assumptions for 2004 is 6 percent and 8.75
percent, respectively.
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 is 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.
16
RESULTS OF OPERATIONS
CONSOLIDATED NET INCOME
Energen Corporation's net income for the year ended December 31, 2003 totaled
$110.7 million, or $3.10 per diluted share compared to year ended December 31,
2002 net income of $68.6 million, or $2.03 per diluted share. This 52.7 percent
increase in earnings per diluted share (EPS) largely reflected the result of
significantly higher prices for natural gas, oil and natural gas liquids as well
as the impact of a 14.8 percent increase in production volumes of Energen's oil
and gas subsidiary, Energen Resources Corporation. Prior-year results included a
$5.7 million after-tax, or $0.17 per diluted share, non-cash benefit from the
Company's previous hedge position with Enron North America Corp. (Enron) and
$14.2 million, or $0.42 per diluted share, of nonconventional fuels tax credits.
Discontinued operations in 2003 reflected a gain of $0.4 million as compared
with a gain of $0.5 million in 2002. Net income in 2002 also included a charge
of $2.2 million after-tax or $0.07 per diluted share, reflecting the cumulative
effect on prior years of the adoption of SFAS No. 143, "Accounting for Asset
Retirement Obligations." For the year ended December 31, 2003, Energen Resources
earned $78.9 million, as compared with $41.2 million in the previous year.
Alabama Gas Corporation (Alagasco), Energen's utility subsidiary, generated a
19.8 percent increase in net income, earning $33 million in the current year as
compared with net income in the prior period of $27.6 million. For the 12 months
ended September 30, 2001, Energen reported earnings of $67.9 million, or $2.18
per diluted share.
2003 VS 2002: Energen Resources' net income rose 91.5 percent to $78.9 million
in 2003. Energen Resources' income from continuing operations before the
cumulative effect of a change in accounting principle totaled $78.5 million in
2003 as compared with $43 million in 2002, primarily due to higher commodity
prices along with the impact of increased gas and oil production volumes due to
a full year's production from the April 2002 acquisition of oil properties in
the Permian Basin, a new gas project in the Permian Basin, acquisitions in the
San Juan Basin and the successful coalbed methane down-spacing program. These
increases were partially offset by higher lease operating expense and increased
depreciation, depletion and amortization (DD&A) expense. Prior year results
included the non-cash benefit associated with the Company's previous hedge
position with Enron and the recognition of $14.2 million in non-conventional
fuels tax credits. The ability to generate new credits ended December 31, 2002.
Alagasco earned net income of $33 million in 2003 as compared with net income of
$27.6 million in 2002. This increase in earnings reflected the utility's ability
to earn on a higher level of equity representing investment in utility plant. It
also reflected the impact of timing differences between quarters as it relates
to revenue recovery under the utility's rate-setting mechanism. Alagasco's
return on average equity (ROE) was 13.5 percent in 2003 compared with 12.3
percent in 2002.
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 2002 included a charge of $2.2 million
after-tax ($0.07 per diluted share) related to the adoption of SFAS No. 143, as
discussed above. Energen Resources' income from continuing operations before the
cumulative effect of a change in accounting principle in 2002 totaled $43
million as compared with $37.1 million in 2001. Positively influencing income
from continuing operations was a 16.9 percent increase in production volumes
related to the acquisition of oil properties in the Permian Basin in April 2002
and the non-cash benefit of $5.7 million after-tax ($0.17 per diluted share)
associated with its previous hedge position with Enron. The primary negative
influences on income from continuing operations were increased DD&A and lease
operating expenses.
Alagasco's earnings increased to $27.6 million in 2002 from $26 million in 2001
as a result of the utility earning on a higher level of equity. Alagasco
achieved a ROE of 12.3 percent in both 2002 and 2001.
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 income from continuing operations of $1.2 million in the December 31,
2001 transition quarter as compared with $8.3 million in the same quarter in the
previous year largely due to a 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
17
the transition quarter were increased DD&A expense and a $1.7 million writedown
on property held for sale. 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 2003, 2002 and 2001 totaled $219.8 million,
$135.8 million and $115 million, respectively. This significant growth in
operating income has been 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 increases in the levels 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 natural gas, oil and
natural gas liquids prices; a full year's production from the 2002 acquisition
of oil properties in the Permian Basin; a new project in the Permian Basin that
produced gas which had previously been reinjected into the reservoir;
acquisitions in the San Juan Basin; and a successful coalbed methane
down-spacing program. During 2003, production from continuing operations rose
14.8 percent to 85.4 billion cubic feet equivalent (Bcfe). Natural gas
production increased 20.3 percent to 55.4 billion cubic feet (Bcf) and oil
volumes rose 13.1 percent to 3,412 thousand barrels (MBbl). Production of
natural gas liquids declined 7.3 percent to 1,587 MBbl. Including the
prior-period non-cash benefit from the former Enron hedges, realized gas prices
increased 34.1 percent to $4.25 per thousand cubic feet (Mcf), realized oil
prices rose 5.9 percent to $25.56 per barrel and natural gas liquids prices
increased 27.8 percent to an average price of $16.32 per barrel during 2003.
In 2002, revenues from oil and gas operations increased primarily as a result of
increased production volumes related to the Permian Basin acquisition. During
2002, production from continuing operations increased 16.9 percent to 74.4 Bcfe.
Natural gas production increased 4.5 percent to 46.1 Bcf, oil volumes rose 61
percent to 3,016 MBbl and natural gas liquids production increased 22.5 percent
to 1,712 MBbl. Including the non-cash benefit from the former Enron hedges,
realized gas prices rose 5.3 percent to $3.17 per Mcf, while realized oil prices
increased 3 percent to $24.13 per barrel. Natural gas liquids prices fell 27.3
percent to an average price of $12.77 per barrel.
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 $6.1 million, $4.8 million and $7.6 million in
2003, 2002 and 2001, respectively.
- --------------------------------------------------------------------------------------------------
DECEMBER 31, December 31, September 30,
Years ended (in thousands, except sales price data) 2003 2002 2001
- --------------------------------------------------------------------------------------------------
Operating revenues from continuing operations
Natural gas $ 235,649 $ 145,935 $ 132,554
Oil 87,200 72,758 43,880
Natural gas liquids 25,890 21,857 24,540
Operating fees 6,077 4,847 7,618
Other (1,694) (1,277) 362
- --------------------------------------------------------------------------------------------------
Total operating revenues from continuing operations $ 353,122 $ 244,120 $ 208,954
- --------------------------------------------------------------------------------------------------
Production volumes from continuing operations
Natural gas (MMcf) 55,433 46,060 44,071
Oil (MBbl) 3,412 3,016 1,873
Natural gas liquids (MBbl) 1,587 1,712 1,397
- --------------------------------------------------------------------------------------------------
Average sales price including effects of hedging
Natural gas (per Mcf) $ 4.25 $ 3.17 $ 3.01
Oil (per barrel) $ 25.56 $ 24.13 $ 23.43
Natural gas liquids (per barrel) $ 16.32 $ 12.77 $ 17.57
- --------------------------------------------------------------------------------------------------
Average sales price excluding effects of hedging
Natural gas (per Mcf) $ 4.97 $ 2.96 $ 4.85
Oil (per barrel) $ 29.19 $ 24.82 $ 27.42
Natural gas liquids (per barrel) $ 18.40 $ 12.77 $ 17.57
- --------------------------------------------------------------------------------------------------
18
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,"Accounting for Impairment or Disposal of Long-Lived
Assets," which was adopted as of January 1, 2002. In 2003, Energen Resources
recorded a pre-tax gain of $9.4 million in discontinued operations from the sale
of properties located in the San Juan Basin and a pre-tax writedown of $10.4
million on certain non-strategic gas properties located in the Gulf Coast
region, which were subsequently sold in 2003 for a pre-tax gain of $0.4 million.
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.
Operations and maintenance (O&M) expense increased $10.8 million and $10.6
million in 2003 and 2002, respectively. Lease operating expense (excluding
production taxes) in 2003 rose $10.8 million primarily due to the acquisition of
oil and gas properties; higher operational costs driven by market conditions
related to increased commodity costs as well as an increased number of wells in
the San Juan and Permian Basins; and increased drilling activity in the coalbed
methane down-spacing program. In 2002, lease operating expense (excluding
production taxes) increased by $7.9 million primarily due to the acquisition of
oil and gas properties. Administrative expense increased $2.8 million and $3.3
million in 2003 and 2002, respectively, primarily due to labor related costs and
additional costs related to the property acquisition. Exploration expense
decreased $2.5 million in 2003 largely due to a $3.2 million pre-tax writedown
of unproved leasehold costs recorded during 2002 offset by increased exploratory
efforts. In 2002, exploration expense decreased $0.6 million primarily due to
decreased exploratory efforts.
DD&A expense increased $11.7 million in 2003 and $17.1 million in 2002 largely
due to increased production volumes. The average depletion rate was $0.92 per
Mcfe in 2003, $0.89 per Mcfe in 2002 and $0.78 per Mcfe in 2001.
Energen Resources' expense for taxes other than income primarily reflected
production-related taxes. Energen Resources recorded severance taxes for 2003 of
$27.7 million as a result of increased commodity prices as well as increased
production. Severance taxes in 2002 and 2001 were $18.3 million and $22.8
million, respectively.
OIL AND GAS OPERATIONS - TRANSITION PERIOD: Revenues from oil and gas continuing
operations declined 8.6 percent to $47 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 12 percent to $2.99 per
Mcf, while realized oil prices rose 10 percent to $24.01 per barrel. Natural gas
liquids prices decreased 51.6 percent to an average price of $10.01 per barrel.
Natural gas production in the transition quarter increased slightly to 11.5 Bcf,
while oil volumes decreased slightly to 464 MBbl. Natural gas liquids production
increased 14.1 percent to 428 MBbl. Natural gas comprised nearly 70 percent of
Energen Resources' production in the transition quarter.
19
- ------------------------------------------------------------------------------------------
DECEMBER 31, December 31,
Three months ended (in thousands, except sales price data) 2001 2000
- ------------------------------------------------------------------------------------------
Revenues from continuing operations
Natural gas production $ 34,290 $ 30,357
Oil production 11,128 10,502
Natural gas liquids production 4,282 7,758
Operating fees 913 2,225
Other (3,659) 555
- ------------------------------------------------------------------------------------------
Total revenues from continuing operations $ 46,954 $ 51,397
- ------------------------------------------------------------------------------------------
Production volumes from continuing operations
Natural gas (MMcf) 11,454 11,364
Oil (MBbl) 464 481
Natural gas liquids (MBbl) 428 375
- ------------------------------------------------------------------------------------------
Average sales price including effects of hedging
Natural gas (per Mcf) $ 2.99 $ 2.67
Oil (per barrel) $ 24.01 $ 21.84
Natural gas liquids (per barrel) $ 10.01 $ 20.70
- ------------------------------------------------------------------------------------------
Average sales price excluding effects of hedging
Natural gas (per Mcf) $ 2.34 $ 5.16
Oil (per barrel) $ 19.52 $ 30.50
Natural gas liquids (per barrel) $ 10.01 $ 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 December 31, 2001 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 $7.8 million in the transition quarter ended December 31,
2001, largely due to the non-cash writedown of $8.7 million pre-tax associated
with Energen Resources' hedge position with Enron. Lease operating expense
decreased by $0.3 million in the transition quarter while exploration expense
declined $0.3 million. Energen Resources' DD&A expense for the period rose $4.1
million primarily driven by the impact of market declines in commodity prices.
The average depletion rate for the transition quarter was $0.89 as compared to
$0.66 for the same period in the previous year.
Energen Resources' expense for taxes other than income taxes primarily reflected
production-related taxes that were $3.2 million lower in the transition quarter
largely 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 utility'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 temperature adjustment mechanism
that requires Alagasco to adjust customer bills monthly to reflect changes in
usage due to departures from normal temperatures. The temperature adjustment
applies primarily to residential, small commercial and small industrial
customers.
Alagasco's natural gas and transportation sales revenues totaled $489.1 million,
$424.4 million and $553.9 million in 2003, 2002 and 2001, respectively. Sales
revenue in 2003 rose largely due to a significant increase in the commodity cost
of gas. 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 2002.
During 2003, weather was comparable to the previous year. Residential sales
volumes increased 3.4 percent and small commercial and industrial volumes
increased 6.1 percent largely due to increased gas usage per customer.
Transportation volumes declined 6.7 percent primarily due to higher gas prices
which resulted in alternate fuel use partially offset by certain nonrecurring
gas deliveries. In 2002, residential sales volumes decreased 15.1 percent
20
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.
Higher commodity gas cost generated a 23.3 percent increase in cost of gas for
2003. 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.
O&M expense at the utility increased 4.6 percent in 2003 primarily due to
increased labor-related costs. In 2002, O&M expense increased 3.1 percent
primarily due to higher insurance and labor-related costs partially offset by
reduced bad debt expense and marketing costs. The increase in O&M expense per
customer for the rate years ended September 30, 2003 and 2002 were slightly
above the inflation-based Cost Control Measurement (CCM) established by the APSC
as part of the utility's rate-setting mechanism; as a result, three quarters of
the difference, or $0.1 million and $0.3 million pre-tax respectively, was
returned to the customers through RSE (see Note 2). In 2001, the increase in O&M
expense on a per-customer basis fell within the CCM.
Depreciation expense rose 10.4 percent in 2003 consistent with the growth in the
utility's depreciable base and with the replacement of support systems with
higher depreciation rates than the average rates applicable to the distribution
system. Depreciation expense rose 8.9 percent in 2002 due to normal growth of
the utility's distribution system. 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.
- -------------------------------------------------------------------------------------------
DECEMBER 31, December 31, September 30,
Years ended (in thousands) 2003 2002 2001
Natural gas transportation and sales revenues $ 489,099 $ 424,431 $ 553,862
Cost of natural gas (236,037) (191,479) (329,572)
Operations and maintenance (114,078) (109,115) (105,812)
Depreciation (37,171) (33,682) (30,933)
Income taxes (19,675) (17,825) (13,448)
Taxes, other than income taxes (34,965) (30,785) (37,257)
- -------------------------------------------------------------------------------------------
Operating income $ 47,173 $ 41,545 $ 36,840
- -------------------------------------------------------------------------------------------
Natural gas sales volumes (MMcf)
Residential 27,248 26,358 31,064
Commercial and industrial-small 12,564 11,838 14,054
- -------------------------------------------------------------------------------------------
Total natural gas sales volumes 39,812 38,196 45,118
Natural gas transportation volumes (MMcf) 55,623 59,644 53,989
- -------------------------------------------------------------------------------------------
Total deliveries (MMcf) 95,435 97,840 99,107
- -------------------------------------------------------------------------------------------
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 transition
quarter, weather that was 30.1 percent warmer than the same period in the prior
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.
21
- --------------------------------------------------------------------------------
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)
Operations and maintenance (27,687) (26,837)
Depreciation (8,151) (7,554)
Income taxes (1,547) (2,094)
Taxes, other than income taxes (7,155) (8,464)
- --------------------------------------------------------------------------------
Operating income $ 6,487 $ 6,498
- --------------------------------------------------------------------------------
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 2003 decreased $1.5 million largely due to a
$32.1 million equity issuance completed in July 2003 which reduced short-term
debt. Current maturities of long-term debt, lower short-term interest rates and
$50 million of long-term debt issued by Energen in October 2003 also influenced
interest expense in the period comparisons. In 2002, interest expense 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). The average daily
outstanding balance under short-term credit facilities was $81.1 million in
2003. The average daily outstanding balance under short-term credit facilities
was $85.6 million in 2002 as compared to $80.7 million in 2001.
Income tax expense increased in 2003 primarily due to higher pre-tax income and
a higher effective tax rate. Income tax expense increased in 2002 and 2001
primarily due to higher pre-tax income. The Company's effective tax rates in
2002 and 2001 were lower than statutory federal tax rates primarily due to the
recognition of nonconventional fuels tax credits. The Company recognized $14.2
million and $13.6 million of nonconventional fuels tax credits in 2002 and 2001,
respectively. The Company's ability to generate nonconventional fuels tax
credits on qualified production ended December 31, 2002, with the expiration of
the credit. As of December 31, 2003, the amount of minimum tax credit that has
been previously recognized and can be carried forward indefinitely to reduce
future regular tax liability is $59.3 million.
TRANSITION PERIOD: Interest expense for the Company increased $0.4 million in
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. 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. The effective tax rate utilized in computing income tax
expense reflected financial recognition of $3.5 million of nonconventional fuels
tax credits as produced during the transition quarter.
FINANCIAL POSITION AND LIQUIDITY
The Company's net cash from operating activities totaled $243.1 million, $213.5
million and $156.5 million in 2003, 2002 and 2001, respectively. Operating cash
flow in 2003 benefited from significantly higher realized
22
commodity prices at Energen Resources; working capital needs at Alagasco in 2003
were affected by increased gas costs resulting in higher storage inventory
balances. In 2002, operating cash flow benefited from significantly higher
production volumes related to Energen Resources' property acquisition and
decreased storage inventory balances at Alagasco. 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 2003, the Company made net investments of $190.4 million. Energen
Resources invested $40.5 million in property acquisitions, $121.9 million for
development costs including approximately $89 million to drill 347 gross
development wells and $0.4 million for exploration. Energen Resources sold or
traded certain properties during the current year, resulting in cash proceeds of
$29.1 million. Utility expenditures in 2003 totaled $57.9 million and primarily
represented system distribution expansion and support facilities, including
information technology application projects. 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 for approximately $77 million. Energen
Resources sold or traded certain properties during 2002, resulting in cash
proceeds of $17.1 million. Utility expenditures in 2002 totaled $65.8 million.
Cash used in investing activities totaled $174.4 million in 2001. Energen
Resources invested $34.3 million for property acquisitions, $103.6 million for
development of proved properties and $1.2 million for exploration during 2001.
Energen Resources drilled 140 gross development wells for approximately $70
million. Energen Resources sold or traded certain properties during 2001,
resulting in cash proceeds of $17.3 million. Utility expenditures for 2001
totaled $56.1 million, including approximately $3 million for a municipal
acquisition.
During 2003, the Company added approximately 101 Bcfe of reserves from
acquisitions and 135 Bcfe of reserves from discoveries and other additions
primarily the result of unit downspacing that increased the number of available
drilling locations for certain wells in the Black Warrior, San Juan and Permian
basins. Energen Resources added approximately 389 Bcfe and 69 Bcfe of reserves
in 2002 and 2001, respectively.
Net cash used in financing activities totaled $55.4 million in 2003. In July
2003, Energen completed the issuance of 1,000,000 shares of common stock through
the periodic draw-down of shares in a shelf registration. The sale of shares
began May 9, 2003, and concluded on July 16, 2003, generating net proceeds of
$32.1 million. In October 2003, Energen issued $50 million of long-term debt due
October 1, 2013. The 5% coupon notes were priced at 99.557 percent to yield
5.057 percent. Long-term debt was reduced by $23 million for current maturities
in 2003. In 2002, net cash provided by financing activities totaled $53 million.
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. 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. 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 as well as 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.
23
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 a total of $639.3 million for
capital projects during the years ended December 31, 2003 and 2002, the three
months ended December 31, 2001, and the year ended September 30, 2001. Property
acquisition expenditures totaled $259.3 million, development activities totaled
$372.7 million, and exploratory expenditures totaled $1.9 million.
- -------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -------------------------------------------------------------------------------------------------------
Capital and exploration expenditures for:
Property acquisitions $ 40,486 $184,177 $ 319 $ 34,316
Development 121,889 122,494 24,757 103,574
Exploration 397 104 228 1,190
Other 1,548 1,880 464 1,477
- -------------------------------------------------------------------------------------------------------
Total 164,320 308,655 25,768 140,557
- -------------------------------------------------------------------------------------------------------
Less exploration expenditures charged to
income 982 3,179 716 3,671
- -------------------------------------------------------------------------------------------------------
Net capital expenditures $163,338 $305,476 $ 25,052 $136,886
- -------------------------------------------------------------------------------------------------------
NATURAL GAS DISTRIBUTION: During the years ended December 31, 2003 and 2002, the
three months ended December 31, 2001, and the year ended September 30, 2001,
Alagasco invested $192.7 million for capital projects: $128.1 million for normal
expansion, replacements and support of its distribution system, $61.6 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 Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -------------------------------------------------------------------------------------------------------
Capital and expenditures for:
Renewals, replacements,
system expansion and other $ 39,883 $ 43,029 $ 8,839 $ 36,340
Support facilities 18,023 22,786 4,034 16,733
Municipal gas system acquisition -- -- -- 3,017
- -------------------------------------------------------------------------------------------------------
Total $ 57,906 $ 65,815 $ 12,873 $ 56,090
- -------------------------------------------------------------------------------------------------------
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,
24
2003, Energen's EPS grew at an average compound rate of 21.9 percent a year.
Over the next five years, Energen is targeting an average EPS growth rate over
each rolling five-year period of approximately 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.
The Company may periodically issue long-term debt and equity to replace
short-term obligations to provide 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. Standard and Poor's last update
in October 2003 confirmed Energen's and Alagasco's rating as A- with a stable
outlook. In February 2003, Moody's Investors Service confirmed Energen's debt
rating as Baa1 and Alagasco's debt rating as A1. While the Company expects to
have ongoing access to its 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 expected
increases in cash flows to help finance Energen Resources' acquisition strategy.
In July 2003, Energen completed the issuance of 1,000,000 shares of common stock
through the periodic draw-down of shares in a shelf registration. In October
2003, the Company issued $50 million of long-term debt. These proceeds were used
for general corporate purposes and to repay a portion of short-term debt
incurred to finance the oil and gas property acquisition program of Energen
Resources.
In 2004, Energen Resources plans to invest approximately $310 million, including
$200 million in property acquisitions, $2 million in related acquisition
development and $108 million in other development and exploratory activities.
Included in this $108 million is approximately $77 million for the development
of previously identified proved undeveloped reserves and approximately $4
million of exploratory exposure. Capital investment at Energen Resources in 2005
is expected to approximate $200 million for property acquisitions, $20 million
for related acquisition development and $52 million for other development and
exploration. Of this $52 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, 2008 is estimated
to be approximately $1.4 billion, with $1.2 billion for property acquisitions
and related development, $200 million for other development and $25 million for
exploratory and other activities. During the five year period, Energen Resources
anticipates spending approximately $137 million on development of previously
identified proved undeveloped reserves and incurring approximately $16 million
in exploratory exposure. 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 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 criteria which could result in
capital expenditures different than those outlined above. These acquisitions or
negotiations to sell, trade or otherwise dispose of properties may alter the
aforementioned financing requirements.
During 2004, Alagasco plans to invest approximately $60 million in utility
capital expenditures for normal distribution and support systems. Alagasco
maintains an investment in storage gas that is expected to average approximately
$35 million in 2004 but may vary depending upon the price of natural gas.
Alagasco plans to invest approximately $53 million in utility capital
expenditures during 2005. 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 December 31, 2008, Alagasco anticipates capital investments of
approximately $275 million. During this period, the Company may issue
approximately $50 million in long-term debt.
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, 2003.
25
- ----------------------------------------------------------------------------------------------------------
PAYMENTS DUE BY PERIOD
------------------------------------------------------------------
LESS THAN AFTER
(in thousands) TOTAL 1 YEAR 1 - 3 YEARS 4 - 5 YEARS 5 YEARS
- ----------------------------------------------------------------------------------------------------------
Short-term cash obligations $ 11,000 $ 11,000 $ -- $ -- $ --
Long-term cash obligations (1) 564,533 10,000 37,000 20,000 497,533
Purchase obligations (2) 242,312 49,227 147,138 37,824 8,123
Capital lease obligations -- -- -- -- --
Operating leases 44,163 3,388 8,151 4,185 28,439
- ----------------------------------------------------------------------------------------------------------
Total contractual cash obligations $862,008 $ 73,615 $192,289 $ 62,009 $534,095
- ----------------------------------------------------------------------------------------------------------
(1) Long-term cash obligations include $1.7 million of unamortized debt
discounts as of December 31, 2003.
(2) Certain of the Company's long-term gas procurement contracts for the supply,
storage and delivery of natural gas include fixed charges of approximately $240
million through October 2013. 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 55.1 Bcf through December 2006.
Alagasco has an agreement with a financial institution whereby it may sell on an
ongoing basis, with recourse, certain installment receivables related to its
merchandising program up to a maximum of $15 million as further described in
Note 8. The fair value of these guarantees is not significant to the Company and
is recorded as a non-current other liability. Effective February 1, 2004,
Alagasco is no longer selling its installment receivables.
OUTLOOK
OIL AND GAS OPERATIONS: Energen Resources plans to continue to implement its
acquisition and development program with capital spending in 2004 and 2005 as
outlined above. Production in 2004 is estimated to be approximately 85 Bcfe,
including 81.6 Bcfe of estimated production from proved reserves owned at
December 31, 2003. In 2005, production is estimated to reach approximately 97
Bcfe, including approximately 77 Bcfe produced from proved reserves currently
owned.
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
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 derivative commodity instruments that
qualify as cash flow hedges under SFAS No. 133 to hedge its exposure to oil,
natural gas and natural gas liquids production. In addition, Alagasco
periodically 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.
26
Energen Resources has entered into the following transactions for 2004 and
subsequent years:
- --------------------------------------------------------------------------------
PRODUCTION TOTAL HEDGED AVERAGE CONTRACT
PERIOD VOLUMES PRICE DESCRIPTION
- --------------------------------------------------------------------------------
NATURAL GAS
- --------------------------------------------------------------------------------
2004 15.8 Bcf $4.83 Mcf NYMEX Swaps
* 1.7 Bcf $5.60 Mcf NYMEX Swaps
20.6 Bcf $4.17 Mcf Basin Specific Swaps
* 4.3 Bcf $5.09 Mcf Basin Specific Swaps
2.4 Bcf $4.05 - $4.44 Mcf NYMEX Collars
2005 1.2 Bcf $3.75 Mcf NYMEX Swaps
6.0 Bcf $3.96 Mcf Basin Specific Swaps
* 4.2 Bcf $4.70 Mcf Basin Specific Swaps
- --------------------------------------------------------------------------------
OIL
- --------------------------------------------------------------------------------
2004 1,428 MBbl $27.75 Bbl NYMEX Swaps
360 MBbl $27.85 Bbl West Texas Sour (WTS) Swaps
* 428 MBbl $30.29 Bbl NYMEX Swaps
* 646 MBbl $27.62 Bbl WTS Swaps
2005 * 300 MBbl $30.50 Bbl NYMEX Swaps
- --------------------------------------------------------------------------------
OIL BASIS DIFFERENTIAL
- --------------------------------------------------------------------------------
2004 300 MBbl ** Basis Swaps
* 60 MBbl ** Basis Swaps
- --------------------------------------------------------------------------------
NATURAL GAS LIQUIDS
- --------------------------------------------------------------------------------
2004 37 MMGal $0.41 Gal Liquids Swaps
- --------------------------------------------------------------------------------
* Contract entered into subsequent to December 31, 2003
** Average contract prices not meaningful due to the varying nature of each
contract
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, 2003, the Company estimated that a 10 percent increase or decrease
in the commodities prices would have resulted in a $29.1 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, 2002 and 2001, the Company estimated that a 10 percent increase
in the commodities prices would have resulted in a $27.2 million and a $2.1
million change, respectively, 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 and a $2.1 million change, respectively, in the fair value of open
derivative contracts. 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 beyond that date, unless, after notice to the Company and a
hearing, the APSC votes to modify or discontinue its operation. Alagasco's rate
schedules for natural gas distribution charges contain a Gas Supply Adjustment
rider which permits the pass-through to customers for changes in the cost of gas
supply. Also as discussed in Note 2, the utility's CCM is based in part on the
number of 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. 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.
27
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 fair value as either assets
or liabilities on the balance sheet. Gains or losses are passed through to
customers using the mechanisms of the GSA in compliance with its APSC-approved
tariff. In accordance with SFAS No. 71, Alagasco had recorded a current
regulatory asset of $0.3 million, a current regulatory liability of $17 million
and a noncurrent regulatory liability of $8.7 million representing the fair
value of derivatives as of December 31, 2003.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS: 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 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, results of operation and cash flows;
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.
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 the month following 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. Energen
Resources monitors the credit quality for its customers 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 account for
approximately 15%, 13% and 12%, respectively, of Energen Resources' estimated
2004 production. Energen Resources' other purchasers each buy less than 11% of
production.
28
RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other
Intangible Assets," were issued by the FASB in June 2001 and became effective on
July 1, 2001, and January 1, 2002, respectively. SFAS No. 141 requires all
business combinations initiated after June 30, 2001, to be accounted for using
the purchase method and SFAS No. 142 establishes new guidelines in accounting
for goodwill and other intangible assets. Under SFAS No. 142, goodwill and
certain intangible assets that have indefinite useful lives are not amortized,
but rather are reviewed annually for impairment. The appropriate application of
SFAS No. 141 and SFAS No. 142 to oil and gas mineral rights held under lease and
other contractual arrangements representing the right to extract such reserves
is currently being considered. One interpretation relative to these standards is
that oil and gas mineral rights for both undeveloped and developed leaseholds
could be classified separately from oil and gas properties as intangible assets
on the balance sheet, rather than as a part of oil and gas properties as
currently recorded. In addition, the disclosures required by SFAS No. 141 and
SFAS No. 142 relative to intangible assets would be included in the notes to the
financial statements. The Company anticipates that this interpretation of SFAS
No. 141 and SFAS No. 142 would only affect balance sheet classifications of oil
and gas leaseholds. Results of operations and cash flows are not anticipated to
be affected, since these oil and gas mineral rights held under lease and other
contractual arrangements representing the right to extract such reserves would
continue to be amortized in accordance with SFAS No. 19, "Financial Accounting
and Reporting by Oil and Gas Producing Companies." The Company will continue to
evaluate the impact of the application of these standards as further guidance is
provided.
The Company adopted the fair value recognition provisions of SFAS No. 123 (as
amended), "Accounting for Stock-Based Compensation," prospectively for all
stock-based employee compensation effective as of January 1, 2003. Awards under
the Company's plan vest over periods ranging from one to four years; therefore,
the cost related to stock-based employee compensation included in the
determination of net income is less than that which would have been recognized
if the fair value method had been applied to all awards since the original
effective date of SFAS No. 123.
In December 2003, the FASB revised SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits - an amendment of FASB Statements No.
87, 88 and 106." The revised Statement added additional disclosures relating to
the assets, obligations, cash flows and net periodic benefit cost of defined
benefit pension plans and other postretirement plans and is effective for
financial statements with fiscal years ending after December 15, 2003, with an
exception for the disclosure of estimated future benefit payments effective for
fiscal years ending after June 15, 2004. The Company has incorporated within
this report the additional required disclosures (See Note 5).
On December 8, 2003, President Bush signed into law a bill that expands
Medicare, adding a prescription drug benefit for Medicare-eligible retirees
starting in 2006. Although the company anticipates that the benefits it pays
after 2006 will be lower as a result of the new Medicare provisions, the retiree
medical obligations and costs reported do not reflect the impact of this
legislation. Deferring the recognition of the new Medicare provisions' impact is
permitted by FASB Staff Position 106-1, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of
2003," due to open issues related to the new Medicare provisions and a lack of
authoritative accounting guidance about certain matters. The final accounting
guidance could require changes to previously reported information.
29
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item with respect to market risk is set forth
in Item 7, 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.
30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
Page
----
1. Financial Statements
ENERGEN CORPORATION
Report of Independent Auditors.............................. 31
Consolidated Statements of Income for the years ended
December 31, 2003and 2002, the three months ended December
31, 2001, and the year ended September 30, 2001............ 32
Consolidated Balance Sheets as of December 31, 2003 and
2002........................................................ 33
Consolidated Statements of Shareholders' Equity for the
years ended December 31, 2003 and 2002, the three months
ended December 31, 2001, and the year ended September 30,
2001........................................................ 35
Consolidated Statements of Cash Flows for the years ended
December 31, 2003 and 2002, the three months ended
December 31, 2001, and the year ended September 30, 2001 ... 36
Notes to Financial Statements............................... 42
ALABAMA GAS CORPORATION
Report of Independent Auditors.............................. 31
Statements of Income for the years ended December 31, 2003
and 2002, the three months ended December 31, 2001, and
the year ended September 30, 2001........................... 37
Balance Sheets as of December 31, 2003 and 2002 ............ 38
Statements of Shareholder's Equity for the years ended
December 31, 2003 and 2002, the three months ended
December 31, 2001, and the year ended September 30, 2001... 40
Statements of Cash Flows for the years ended December 31,
2003 and 2002,the three months ended December 31, 2001,
and the year ended September30, 2001........................ 41
Notes to Financial Statements............................... 42
2. Financial Statement Schedules
ENERGEN CORPORATION
Schedule II - Valuation and Qualifying Accounts............. 76
ALABAMA GAS CORPORATION
Schedule II - Valuation and Qualifying Accounts............. 76
Schedules other than those listed above are omitted because they are not
required or not applicable, or the required information is shown in the
financial statements or notes thereto.
31
REPORT OF INDEPENDENT AUDITORS
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF ENERGEN CORPORATION:
In our opinion, the consolidated financial statements of Energen Corporation
listed in the accompanying index present fairly, in all material respects, the
financial position of Energen Corporation and subsidiaries at December 31, 2003
and 2002, and the results of their operations and their cash flows for the years
ended December 31, 2003 and 2002, the three months ended December 31, 2001 and
the year ended September 30, 2001, 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 schedule are the responsibility of the
Company's management; 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 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 amounts 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 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. As discussed
in Note 1 of the Notes to the Financial Statements, effective October 1, 2000,
the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities."
PricewaterhouseCoopers LLP
Birmingham, Alabama
March 2, 2004
REPORT OF INDEPENDENT AUDITORS
TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF ALABAMA GAS CORPORATION:
In our opinion, the financial statements of Alabama Gas Corporation listed in
the accompanying index present fairly, in all material respects, the financial
position of Alabama Gas Corporation at December 31, 2003 and 2002, and the
results of its operations and its cash flows for the years ended December 31,
2003 and 2002, the three months ended December 31, 2001 and the year ended
September 30, 2001, 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 financial statements. These financial statements and financial
statement schedule are the responsibility of the Company's management; 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 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 amounts 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 our opinion.
PricewaterhouseCoopers LLP
Birmingham, Alabama
March 2, 2004
32
CONSOLIDATED STATEMENTS OF INCOME
ENERGEN CORPORATION
- -------------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands, except share data) 2003 2002 2001 2001
- -------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Oil and gas operations $ 353,122 $ 244,120 $ 46,954 $ 208,954
Natural gas distribution 489,099 424,431 96,678 553,862
- -------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 842,221 668,551 143,632 762,816
- -------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas 233,823 189,810 45,291 327,531
Operations and maintenance 208,219 191,656 53,032 177,688
Depreciation, depletion and amortization 116,858 101,691 23,468 81,840
Taxes, other than income taxes 63,543 49,619 10,728 60,731
Accretion expense 1,890 1,819 -- --
- -------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 624,333 534,595 132,519 647,790
- -------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 217,888 133,956 11,113 115,026
- -------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense (42,262) (43,713) (10,634) (42,070)
Other income 8,744 15,644 4,354 16,825
Other expense (9,977) (15,103) (4,385) (14,892)
- -------------------------------------------------------------------------------------------------------------------------------
Total other expense (43,495) (43,172) (10,665) (40,137)
- -------------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 174,393 90,784 448 74,889
Income tax expense (benefit) 64,128 20,388 (3,282) 12,472
- -------------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 110,265 70,396 3,730 62,417
- -------------------------------------------------------------------------------------------------------------------------------
DISCONTINUED OPERATIONS, NET OF TAXES
Income (loss) from discontinued operations 973 (80) (72) 5,479
Gain (loss) on disposal (584) 543 -- --
- -------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) FROM DISCONTINUED OPERATIONS 389 463 (72) 5,479
- -------------------------------------------------------------------------------------------------------------------------------
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF TAXES -- (2,220) -- --
- -------------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 110,654 $ 68,639 $ 3,658 $ 67,896
- -------------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER AVERAGE COMMON SHARE
Continuing operations $ 3.09 $ 2.08 $ 0.12 $ 2.01
Discontinued operations 0.01 0.02 -- 0.17
Cumulative effect of change in accounting principle -- (0.07) -- --
- -------------------------------------------------------------------------------------------------------------------------------
Net Income $ 3.10 $ 2.03 $ 0.12 $ 2.18
- -------------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS PER AVERAGE COMMON SHARE
Continuing operations $ 3.11 $ 2.09 $ 0.12 $ 2.03
Discontinued operations 0.01 0.02 -- 0.18
Cumulative effect of change in accounting principle -- (0.07) -- --
- -------------------------------------------------------------------------------------------------------------------------------
Net Income $ 3.12 $ 2.04 $ 0.12 $ 2.21
- -------------------------------------------------------------------------------------------------------------------------------
DILUTED AVERAGE COMMON SHARES OUTSTANDING 35,716,876 33,838,299 31,277,406 31,083,784
- -------------------------------------------------------------------------------------------------------------------------------
BASIC AVERAGE COMMON SHARES OUTSTANDING 35,434,486 33,604,601 31,052,152 30,725,919
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these
statements.
33
CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
- ----------------------------------------------------------------------------------------------
DECEMBER 31, December 31,
(in thousands) 2003 2002
- ----------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 2,127 $ 4,804
Accounts receivable, net of allowance for doubtful accounts
of $9,852 at December 31, 2003, and of $8,874 at
December 31, 2002 172,915 139,356
Inventories, at average cost
Storage gas inventory 40,654 23,668
Materials and supplies 7,677 8,335
Liquified natural gas in storage 3,475 3,671
Deferred income taxes 38,145 33,941
Prepayments and other 25,073 20,367
- ----------------------------------------------------------------------------------------------
Total current assets 290,066 234,142
- ----------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, successful efforts method 1,197,340 1,103,472
Less accumulated depreciation, depletion and amortization 310,368 269,616
- ----------------------------------------------------------------------------------------------
Oil and gas properties, net 886,972 833,856
- ----------------------------------------------------------------------------------------------
Utility plant 883,225 825,421
Less accumulated depreciation 341,787 313,414
- ----------------------------------------------------------------------------------------------
Utility plant, net 541,438 512,007
- ----------------------------------------------------------------------------------------------
Other property, net 5,041 5,691
- ----------------------------------------------------------------------------------------------
Total property, plant and equipment, net 1,433,451 1,351,554
- ----------------------------------------------------------------------------------------------
OTHER ASSETS
Deferred income taxes -- 16,333
Regulatory asset 18,082 14,744
Deferred charges and other 39,833 26,239
- ----------------------------------------------------------------------------------------------
Total other assets 57,915 57,316
- ----------------------------------------------------------------------------------------------
TOTAL ASSETS $1,781,432 $1,643,012
- ----------------------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these
statements.
34
CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
- -----------------------------------------------------------------------------------------------
DECEMBER 31, December 31,
(in thousands, except share data) 2003 2002
- -----------------------------------------------------------------------------------------------
CAPITAL AND LIABILITIES
CURRENT LIABILITIES
Long-term debt due within one year $ 10,000 $ 23,000
Notes payable to banks 11,000 113,000
Accounts payable 135,319 103,964
Accrued taxes 28,551 27,936
Customers' deposits 17,884 17,404
Amounts due customers 8,571 8,458
Accrued wages and benefits 24,957 23,652
Regulatory liability 54,146 41,184
Other 37,303 34,710
- -----------------------------------------------------------------------------------------------
Total current liabilities 327,731 393,308
- -----------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Asset retirement obligation 26,515 27,235
Minimum pension liability 17,911 25,825
Regulatory liability 113,427 96,219
Deferred income taxes 33,200 --
Other 10,774 4,661
- -----------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 201,827 153,940
- -----------------------------------------------------------------------------------------------
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, 36,223,531 shares outstanding at December
31, 2003, and 34,745,477 shares outstanding at December
31, 2002 362 347
Premium on capital stock 367,765 320,060
Capital surplus 2,802 2,802
Retained earnings 360,001 275,266
Accumulated other comprehensive income (loss), net of tax
Unrealized gain (loss) on hedges (21,714) (10,471)
Minimum pension liability (8,881) (4,340)
Deferred compensation on restricted stock (1,258) (770)
Deferred compensation plan 17,063 10,348
Treasury stock, at cost; 415,869 shares and 358,228 shares at
December 31, 2003 and 2002, respectively (17,108) (10,432)
- -----------------------------------------------------------------------------------------------
Total common shareholders' equity 699,032 582,810
Long-term debt 552,842 512,954
- -----------------------------------------------------------------------------------------------
Total capitalization 1,251,874 1,095,764
- -----------------------------------------------------------------------------------------------
TOTAL CAPITAL AND LIABILITIES $ 1,781,432 $ 1,643,012
- -----------------------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these
statements.
35
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, 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 income
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
Net income 110,654
Other comprehensive income (loss):
Current period change in fair value
of derivative instruments, net of
tax of ($29,019)
Reclassification adjustment, net of
tax of $21,830
Minimum pension liability, net of
tax of ($2,445)
Comprehensive income
Purchase of treasury shares
Shares issued for:
Stock offerings 1,000,000 10 32,121
Dividend reinvestment plan 53,990 1 1,865
Employee benefit plans 424,064 4 12,033
Deferred compensation obligation
Issuance of restricted stock
Amortization of restricted stock
Stock based compensation 270
Tax benefit from exercise of stock options 1,416
Cash dividends - $0.73 per share (25,919)
- ---------------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2003 36,223,531 $362 $367,765 $2,802 $ 360,001
- ---------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
ACCUMULATED
OTHER DEFERRED
COMPREHENSIVE COMPENSATION DEFERRED
INCOME RESTRICTED COMPENSATION TREASURY SHAREHOLDERS'
(LOSS) STOCK PLAN STOCK EQUITY
- ---------------------------------------------------------------------------------------------------------------------------
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 (55,416)
tax of ($35,430) (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 income 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
Net income 110,654
Other comprehensive income (loss):
Current period change in fair value
of derivative instruments, net of
tax of ($29,019) (45,388) (45,388)
Reclassification adjustment, net of
tax of $21,830 34,145 34,145
Minimum pension liability, net of (4,541) (4,541)
tax of ($2,445) -------
Comprehensive income 94,870
-------
Purchase of treasury shares (1,046) (1,046)
Shares issued for:
Stock offerings 32,131
Dividend reinvestment plan 491 2,357
Employee benefit plans 594 12,631
Deferred compensation obligation 6,715 (6,715) --
Issuance of restricted stock (1,564) (1,564)
Amortization of restricted stock 1,076 1,076
Stock based compensation 270
Tax benefit from exercise of stock options 1,416
Cash dividends - $0.73 per share (25,919)
- ---------------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2003 $(30,595) $(1,258) $17,063 $(17,108) $ 699,032
- ---------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these
statements.
36
CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
- -------------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $ 110,654 $ 68,639 $ 3,658 $ 67,896
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization 117,785 107,952 25,184 86,975
Deferred income taxes, net 54,632 10,915 (8,495) 5,349
Deferred investment tax credits, net (448) (448) (112) (448)
Change in derivative fair value 735 (9,205) (174) (879)
(Gain) loss on sale of assets (9,987) (3,738) 3,161 (4,716)
Loss on properties held for sale 10,404 2,815 -- 3,821
Cumulative effect of change in accounting
principle, net of taxes -- 2,220 -- --
Net change in:
Accounts receivable (24,811) (27,104) (17,529) 19,565
Inventories (16,132) 27,344 7,239 (22,018)
Accounts payable 12,860 28,600 2,442 16,544
Amounts due customers 4,052 626 11,637 (11,655)
Other current assets and liabilities (5,533) 1,712 (4,813) 1,424
Other, net (11,084) 3,179 (837) (5,362)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 243,127 213,507 21,361 156,496
- -------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property, plant and equipment (219,593) (166,075) (37,752) (190,695)
Acquisition, net of cash acquired -- (117,043) -- --
Proceeds from sale of assets 29,149 17,094 2,323 17,326
Other, net 30 (2,198) (252) (1,038)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash (used in) investing activities (190,414) (268,222) (35,681) (174,407)
- -------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Payment of dividends on common stock (25,919) (23,927) (5,458) (21,103)
Issuance of common stock 47,119 12,371 5,172 21,285
Purchase of treasury stock (1,046) (133) (1,245) (2,516)
Reduction of long-term debt (23,000) (21,204) -- (36,267)
Proceeds from issuance of long-term debt 49,778 -- -- 223,799
Debt issuance costs (322) -- -- (4,777)
Net change in short-term debt (102,000) 85,930 17,000 (161,000)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing
activities (55,390) 53,037 15,469 19,421
- -------------------------------------------------------------------------------------------------------------------------------
Net change in cash and cash equivalents (2,677) (1,678) 1,149 1,510
Cash and cash equivalents at beginning of period 4,804 6,482 5,333 3,823
- -------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 2,127 $ 4,804 $ 6,482 $ 5,333
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these
statements.
37
STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
- -------------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 489,099 $ 424,431 $ 96,678 $ 553,862
- -------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas 236,037 191,479 45,651 329,572
Operations and maintenance 114,078 109,115 27,687 105,812
Depreciation 37,171 33,682 8,151 30,933
Income taxes
Current 6,577 8,764 10,348 16,995
Deferred, net 13,546 9,509 (8,689) (3,099)
Deferred investment tax credits, net (448) (448) (112) (448)
Taxes, other than income taxes 34,965 30,785 7,155 37,257
- -------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 441,926 382,886 90,191 517,022
- -------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 47,173 41,545 6,487 36,840
- -------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Allowance for funds used during construction 948 1,336 122 2,098
Other income 4,132 5,520 1,596 5,978
Other expense (5,269) (6,280) (1,838) (6,585)
- -------------------------------------------------------------------------------------------------------------------------------
Total other income (expense) (189) 576 (120) 1,491
- -------------------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt 12,815 13,153 3,327 8,803
Other interest charges 1,152 1,404 353 3,513
- -------------------------------------------------------------------------------------------------------------------------------
Total interest charges 13,967 14,557 3,680 12,316
- -------------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 33,017 $ 27,564 $ 2,687 $ 26,015
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these
statements.
38
BALANCE SHEETS
ALABAMA GAS CORPORATION
- --------------------------------------------------------------------------------
DECEMBER 31, December 31,
(in thousands) 2003 2002
- --------------------------------------------------------------------------------
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant $ 883,225 $ 825,421
Less accumulated depreciation 341,787 313,414
- --------------------------------------------------------------------------------
Utility plant, net 541,438 512,007
- --------------------------------------------------------------------------------
Other property, net 331 842
- --------------------------------------------------------------------------------
CURRENT ASSETS
Cash 1,440 2,818
Accounts receivable
Gas 134,376 108,630
Merchandise 1,210 1,748
Other 1,018 656
Allowance for doubtful accounts (9,100) (8,200)
Inventories, at average cost
Storage gas inventory 40,654 23,668
Materials and supplies 5,527 5,049
Liquified natural gas in storage 3,475 3,671
Regulatory asset 251 --
Deferred income taxes 17,650 20,093
Prepayments and other 22,056 18,314
- --------------------------------------------------------------------------------
Total current assets 218,557 176,447
- --------------------------------------------------------------------------------
OTHER ASSETS
Regulatory asset 18,082 14,744
Deferred charges and other 19,285 11,290
- --------------------------------------------------------------------------------
Total other assets 37,367 26,034
- --------------------------------------------------------------------------------
TOTAL ASSETS $ 797,693 $ 715,330
- --------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these
statements.
39
BALANCE SHEETS
ALABAMA GAS CORPORATION
- ----------------------------------------------------------------------------------
DECEMBER 31, December 31,
(in thousands, except share data) 2003 2002
- ----------------------------------------------------------------------------------
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 at
December 31, 2003 and 2002, respectively 20 20
Premium on capital stock 31,682 31,682
Capital surplus 2,802 2,802
Retained earnings 215,869 182,852
- ----------------------------------------------------------------------------------
Total common shareholder's equity 250,373 217,356
Long-term debt 169,533 169,533
- ----------------------------------------------------------------------------------
Total capitalization 419,906 386,889
- ----------------------------------------------------------------------------------
CURRENT LIABILITIES
Long-term debt due within one year -- 15,000
Notes payable to banks 11,000 13,000
Accounts payable
Trade 56,020 55,720
Affiliated companies 37,290 1,432
Accrued taxes 22,145 24,044
Customers' deposits 17,884 17,404
Amounts due customers 8,571 8,458
Accrued wages and benefits 6,247 5,710
Regulatory liability 54,146 41,184
Other 9,039 8,947
- ----------------------------------------------------------------------------------
Total current liabilities 222,342 190,899
- ----------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 32,178 20,747
Minimum pension liability 6,988 18,661
Regulatory liability 113,427 96,219
Customer advances for construction and other 2,852 1,915
- ----------------------------------------------------------------------------------
Total deferred credits and other liabilities 155,445 137,542
- ----------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
- ----------------------------------------------------------------------------------
TOTAL CAPITAL AND LIABILITIES $797,693 $715,330
- ----------------------------------------------------------------------------------
40
STATEMENTS OF SHAREHOLDER'S EQUITY
ALABAMA GAS CORPORATION
- ----------------------------------------------------------------------------------------------------------------------
COMMON STOCK
------------
TOTAL
(in thousands, except NUMBER OF PAR PREMIUM ON CAPITAL RETAINED SHAREHOLDER'S
share amounts) SHARES VALUE CAPITAL STOCK SURPLUS EARNINGS EQUITY
- ----------------------------------------------------------------------------------------------------------------------
BALANCE SEPTEMBER 30, 2000 1,972,052 $ 20 $ 31,682 $ 2,802 $ 164,767 $199,271
Net income 26,015 26,015
Cash dividends (15,897) (15,897)
- ----------------------------------------------------------------------------------------------------------------------
BALANCE SEPTEMBER 30, 2001 1,972,052 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
Net income 33,017 33,017
- ----------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2003 1,972,052 $ 20 $ 31,682 $ 2,802 $ 215,869 $250,373
- ----------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these
statements.
41
STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
- -------------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $ 33,017 $ 27,564 $ 2,687 $ 26,015
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization 37,171 33,682 8,151 30,933
Deferred income taxes, net 13,546 9,509 (8,689) (3,099)
Deferred investment tax credits (448) (448) (112) (448)
Net change in:
Accounts receivable (15,923) (17,151) (24,648) 6,056
Inventories (17,268) 27,099 5,968 (20,351)
Accounts payable 49 21,697 1,945 (7,298)
Amounts due customers 4,052 626 11,637 (11,655)
Other current assets and liabilities (4,140) (6,666) 1,191 7,692
Other, net (13,774) (1,447) (201) (2,231)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by operating
activities 36,282 94,465 (2,071) 25,614
- -------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property, plant and equipment (56,255) (64,257) (12,820) (53,749)
Net advances from (to) parent company 35,858 (1,622) 3,990 (2,093)
Other, net (263) (814) 143 (327)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash (used in) investing activities (20,660) (66,693) (8,687) (56,169)
- -------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Payment of dividends on common stock -- (16,859) (5,425) (15,897)
Reduction of long-term debt (15,000) (5,467) -- --
Proceeds from issuance of long-term debt -- -- -- 75,000
Debt issuance costs -- -- -- (3,709)
Net change in short-term debt (2,000) (6,000) 18,000 (24,150)
- -------------------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing
activities (17,000) (28,326) 12,575 31,244
- -------------------------------------------------------------------------------------------------------------------------------
Net change in cash and cash equivalents (1,378) (554) 1,817 689
Cash and cash equivalents at beginning of period 2,818 3,372 1,555 866
- -------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 1,440 $ 2,818 $ 3,372 $ 1,555
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these
statements.
42
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Energen Corporation (Energen or the Company) is a diversified energy holding
company engaged primarily in the acquisition, 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
principally in central and north Alabama (natural gas distribution). The
following is a description of the 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 is 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, gas and natural gas liquid 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 units-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, gas and natural gas liquids production
revenue. Under the sales method, revenues are based on actual sales
volumes of commodities sold to purchasers. 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,
2003.
DERIVATIVE COMMODITY INSTRUMENTS: Energen Resources periodically enters
into 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.
43
On October 1, 2000 the Company adopted Statement of Financial Accounting
Standard (SFAS) No. 133 (as amended), "Accounting for Derivative
Instruments and Hedging Activities," which 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 as operating revenues
when the forecasted transaction affects earnings. The ineffective portion
of a derivative's change in fair value is recognized in operating revenues
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 operating revenues in the period of change. As of December
31, 2003, 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, 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 December 31, 2005.
C. NATURAL GAS DISTRIBUTION
UTILITY PLANT AND DEPRECIATION: Property, plant and equipment is stated at
cost. The cost of 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 is charged to the accumulated reserve for depreciation. The
estimated net removal costs on certain gas distribution assets is charged
through depreciation and recognized as a regulatory liability in
accordance with regulatory accounting. 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 4.5 percent in the
years ended December 31, 2003 and 2002, for the three months ended
December 31, 2001 and for the year ended September 30, 2001.
INVENTORIES: Inventories, which consist primarily of gas stored
underground, are stated at average cost.
OPERATING REVENUE AND GAS COSTS: Alagasco records natural gas distribution
revenues in accordance with its tarriff established by the APSC. The
margin and gas costs on service delivered to cycle customers but not yet
billed are recorded in current assets as accounts receivable with a
corresponding regulatory liability.
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.
44
DERIVATIVE COMMODITY INSTRUMENTS: Alagasco periodically enters into cash
flow derivative commodity instruments to hedge its exposure to price
fluctuations on its gas supply. 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 and accordingly are recognized as a
regulatory asset or liability 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 Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- --------------------------------------------------------------------------------------------
Taxes on revenues $ 25,218 $ 21,591 $ 4,969 $ 28,766
- --------------------------------------------------------------------------------------------
D. INCOME TAXES
The 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 between the
financial statement basis and the tax basis of assets and liabilities 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. Consolidated federal income taxes are allocated to appropriate
subsidiaries using the separate return method.
E. CASH EQUIVALENTS
The Company includes highly liquid marketable securities and debt
instruments purchased with a maturity of three months or less in cash
equivalents.
F. 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 adopted the fair value recognition provisions of SFAS No. 123
(as amended), "Accounting for Stock-Based Compensation," prospectively for
all stock-based employee compensation effective as of January 1, 2003.
Awards under the Company's plan vest over periods ranging from one to six
years; therefore, the cost related to stock-based employee compensation
included in the determination of net income is less than that which would
have been recognized if the fair value method had been applied to all
awards since the original effective date of SFAS No. 123. The following
table illustrates the effect on net income and diluted earnings per share
as if the fair value based method had been applied to all outstanding and
unvested awards in each period:
45
- -------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -------------------------------------------------------------------------------------------------------------------------
Net income
As reported $110,654 $68,639 $3,658 $67,896
Stock based compensation expense included in
reported net income, net of tax 4,553 1,811 573 1,820
Stock based compensation expense determined
under fair value based method, net of tax (3,904) (2,413) (539) (2,158)
- -------------------------------------------------------------------------------------------------------------------------
Pro forma $111,303 $68,037 $3,692 $67,558
- -------------------------------------------------------------------------------------------------------------------------
Diluted earnings per average common share
As reported $3.10 $2.03 $0.12 $2.18
Pro forma $3.12 $2.01 $0.12 $2.17
- -------------------------------------------------------------------------------------------------------------------------
Basic earnings per average common share
As reported $3.12 $2.04 $0.12 $2.21
Pro forma $3.14 $2.02 $0.12 $2.20
- -------------------------------------------------------------------------------------------------------------------------
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 for the year ended December 31, 2003 and
the three months ended December 31, 2001, and 36.35 percent for the year
ended September 30, 2001; a risk-free interest rate of 2.36 percent, 3.36
percent and 4.14 percent for the year ended December 31, 2003, the three
months ended December 31, 2001, and the year ended September 30, 2001,
respectively; and a dividend yield of 3.12 percent and 2.55 percent on
options without dividend equivalents for the three months ended December
31, 2001, and the year ended September 30, 2001, respectively. Options
with dividend equivalents assume no dividend yield for all periods
presented. The weighted-average grant-date fair value for options granted
with dividend equivalents during the year ended December 31, 2003 was
$12.10; $9.74 for options granted with dividend equivalents and $6.52 for
options granted without dividend equivalents during the three months ended
December 31, 2001; $12.66 for options granted with dividend equivalents
and $9.27 for options granted without dividend equivalents during the
year-ended September 30, 2001. 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 make estimates and assumptions that affect the reported
amounts of assets and liabilities at the date of the financial statements
and the reported amount of revenues and expenses during the reporting
period. The major estimates and assumptions identified by management
include but are not limited to estimates of physical quantities of oil and
gas reserves, periodic assessments of oil and gas properties for
impairment, an assumption that SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation," will continue as the applicable accounting
standard for the Company's regulated operations and estimates used in
determining the Company's obligations under its employee pension plans.
Due to the inherent uncertainty involved in making estimates, actual
results reported in future periods may differ from the estimates.
2. REGULATORY MATTERS
All of Alagasco's utility operations are conducted in the state of Alabama.
Alagasco is subject to regulation by the APSC which established the Rate
Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was
extended with modifications in 2002, 1996, 1990, 1987 and 1985. On June 10,
2002, the APSC extended Alagasco's rate-setting methodology, RSE, without
change, for a six-year period through January 1, 2008. 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
operations. Alagasco's allowed range of return
46
on equity remains 13.15 percent to 13.65 percent throughout the term of the
order, subject to change in the event that the Commission, 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 year-to-date
performance, whether Alagasco's return on average equity at the end 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 rate year,
effective December 1, and cannot exceed 4 percent of prior-year revenues. As of
September 30, 2003, Alagasco had a $3 million reduction in revenues to bring the
return on average equity within the allowed range of return. 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 Alagasco's operations and maintenance (O&M) expense. Under 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
points above or below the percentage change in the Consumer Price Index For All
Urban Consumers (index range), no adjustment is required. If the change in O&M
expense per customer exceeds the index range, three-quarters of the difference
is returned to customers. To the extent the change is less than the index range,
the utility benefits by one-half of the difference through future rate
adjustments. The increase in O&M expense per customer was slightly above the
index range for the rate year ended September 30, 2003 and 2002; as a result,
the utility returned to customers $0.1 million pre-tax and $0.3 million pre-tax
through rate adjustments under the provisions of RSE. An $11.2 million, $12.7
million and $16.3 million annual increase in revenues became effective December
1, 2003, 2002, and 2001, respectively, under RSE.
Alagasco calculates a temperature adjustment to customers' monthly bills to
substantially remove the effect of departures from normal temperatures on
Alagasco's earnings. Adjustments to customers' bills are made in the same
billing cycle in which the weather variation occurs. The temperature adjustment
applies primarily to residential, small commercial and small industrial
customers. Alagasco's rate schedules for natural gas distribution charges
contain a GSA rider, established in 1993, which permits the pass-through to
customers of changes in the cost of gas supply.
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 full amount of: (1) extraordinary O&M expenses resulting from force
majeure events such as storms, severe weather, and outages, when one or 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 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 ESR is
made, the APSC provides for accretions to the ESR of no more than $40,000
monthly until the maximum funding level is achieved. The ESR balances of $3.5
million at December 31, 2003 and $3 million at December 31, 2002, are included
in the consolidated financial statements.
At December 31, 2003 and 2002, Alagasco had a $21.7 million and an $18.7
million, respectively, gross additional minimum pension liability related to its
salaried and union pension plans. In accordance with SFAS No. 71, "Accounting
for the Effects of Certain Types of Regulation," Alagasco has established a
regulatory asset of $18.1 million and $14.7 million for the accrued obligation
to be recovered through rates in future periods at December 31, 2003 and 2002,
respectively.
During 2003, Alagasco revised its balance sheet presentation to reflect the
margin on service delivered to cycle customers but not yet billed in current
assets as accounts receivable with a corresponding regulatory liability and has
reclassified deferred gas costs as accounts receivable. As a result, current
assets and regulatory liability increased $26.1 million and $17.4 million at
December 31, 2003 and 2002, respectively.
47
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, 2003 and 2002, the net acquisition
adjustments were $12.6 million and $13.8 million, respectively.
3. LONG-TERM DEBT AND NOTES PAYABLE
Long-term debt consisted of the following:
- ---------------------------------------------------------------------------------------------------------
(in thousands) DECEMBER 31, 2003 December 31, 2002
- ---------------------------------------------------------------------------------------------------------
Energen Corporation:
Medium-term Notes, interest ranging from 6.81% to 8.09%,
for notes redeemable July 14, 2004, to February 15, 2028 $ 345,000 $ 353,000
5% Notes, redeemable October 1, 2013 50,000 --
Alabama Gas Corporation:
Medium-term Notes, interest ranging from 6.35% to 7.97%,
for notes redeemable July 15, 2005, to September 23, 2026 95,000 110,000
6.25% Notes, redeemable September 1, 2016 39,758 39,758
6.75% Notes, redeemable September 1, 2031 34,775 34,775
- ---------------------------------------------------------------------------------------------------------
Total 564,533 537,533
Less amounts due within one year 10,000 23,000
Less unamortized debt discount 1,691 1,579
- ---------------------------------------------------------------------------------------------------------
Total $ 552,842 $ 512,954
- ---------------------------------------------------------------------------------------------------------
The aggregate maturities of Energen's long-term debt for the next five years are
as follows:
- --------------------------------------------------------------------------------
Years ending December 31, (in thousands)
- --------------------------------------------------------------------------------
2004 2005 2006 2007 2008
- --------------------------------------------------------------------------------
$ 10,000 $ 10,000 $ 20,000 $ 7,000 $ 15,000
- --------------------------------------------------------------------------------
The aggregate maturities of Alagasco's long-term debt for the next five years
are as follows:
- --------------------------------------------------------------------------------
Years ending December 31, (in thousands)
- --------------------------------------------------------------------------------
2004 2005 2006 2007 2008
- --------------------------------------------------------------------------------
$ -- $ 10,000 $ 10,000 $ 7,000 $ 5,000
- --------------------------------------------------------------------------------
At December 31, 2003, 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, 2003. 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, 2003, 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:
- -----------------------------------------------------------------------------------------------
(in thousands) DECEMBER 31, 2003 December 31, 2002
- -----------------------------------------------------------------------------------------------
Energen outstanding $ -- $100,000
Alagasco outstanding 11,000 13,000
- -----------------------------------------------------------------------------------------------
Notes payable to banks 11,000 113,000
Available for borrowings 256,000 154,000
- -----------------------------------------------------------------------------------------------
Total $267,000 $267,000
- -----------------------------------------------------------------------------------------------
Maximum amount outstanding at any month-end $ 83,000 $113,000
48
Average daily amount outstanding $ 81,121 $ 85,644
Weighted average interest rates based on:
Average daily amount outstanding 1.71% 2.28%
Amount outstanding at year-end 1.42% 1.88%
- -----------------------------------------------------------------------------------------------
Alagasco maximum amount outstanding at any month-end $ 11,000 $ 21,000
Alagasco average daily amount outstanding $ 9,592 $ 3,304
Alagasco weighted average interest rates based on:
Average daily amount outstanding 1.53% 2.18%
Amount outstanding at year-end 1.42% 1.78%
- -----------------------------------------------------------------------------------------------
Energen's total interest expense was $42,262,000 and $43,713,000 for the years
ended December 31, 2003 and 2002, respectively, $10,634,000 for the three months
ended December 31, 2001 and $42,070,000 for the year ended September 31, 2001.
Total interest expense at Alagasco was $13,967,000 and $14,557,000 for the years
ended December 31, 2003 and 2002, respectively, $3,680,000 for the three months
ended December 31, 2001 and $12,316,000 for the year ended September 30, 2001.
4. INCOME TAXES
The components of Energen's income taxes consisted of the following:
- ------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- ------------------------------------------------------------------------------------------------------------
Taxes estimated to be payable currently:
Federal $ 8,904 $ 7,263 $ 3,774 $ 6,498
State 1,294 535 1,551 1,073
- ------------------------------------------------------------------------------------------------------------
Total current 10,198 7,798 5,325 7,571
- ------------------------------------------------------------------------------------------------------------
Taxes deferred:
Federal 47,805 9,062 (7,211) 3,073
State 6,125 3,528 (1,396) 1,828
- ------------------------------------------------------------------------------------------------------------
Total deferred 53,930 12,590 (8,607) 4,901
- ------------------------------------------------------------------------------------------------------------
Total income tax expense (benefit) from
continuing operations $ 64,128 $ 20,388 $ (3,282) $ 12,472
- ------------------------------------------------------------------------------------------------------------
In addition, Energen recorded income tax expense (benefit), related to income
from discontinued operations, of ($5,000) in current income tax benefit and
$254,000 in deferred income tax expense for the year ended December 31, 2003,
$2,418,000 in current income tax expense and ($2,123,000) in deferred income tax
benefit for the year ended December 31, 2002, ($43,000) in current income tax
benefit for the three months ended December 31, 2001, and $3,504,000 in current
income tax expense for the year ended September 30, 2001.
The components of Alagasco's income taxes consisted of the following:
- ------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- ------------------------------------------------------------------------------------------------------------
Taxes estimated to be payable currently:
Federal $ 5,827 $ 7,763 $ 9,167 $ 15,456
State 750 1,001 1,181 1,539
- ------------------------------------------------------------------------------------------------------------
Total current 6,577 8,764 10,348 16,995
- ------------------------------------------------------------------------------------------------------------
Taxes deferred:
Federal 11,549 7,974 (7,807) (3,193)
State 1,549 1,087 (994) (354)
- ------------------------------------------------------------------------------------------------------------
Total deferred 13,098 9,061 (8,801) (3,547)
- ------------------------------------------------------------------------------------------------------------
Total income tax expense from continuing
Operations $ 19,675 $ 17,825 $ 1,547 $ 13,448
- ------------------------------------------------------------------------------------------------------------
49
Temporary differences and carryforwards which gave rise to a significant portion
of Energen's and Alagasco's deferred tax assets and liabilities for 2003, 2002
and 2001 were as follows:
- --------------------------------------------------------------------------------------------------------------
Energen Corporation
- --------------------------------------------------------------------------------------------------------------
(in thousands) DECEMBER 31, 2003 December 31, 2002
- --------------------------------------------------------------------------------------------------------------
CURRENT NONCURRENT Current Noncurrent
-------------------------------------------------------------
Deferred tax assets:
Minimum tax credit $ -- $ 59,313 $ -- $ 64,756
Pension and other costs -- 8,093 5,326 7,056
Unbilled and deferred revenue 10,578 -- 8,690 --
Enhanced stability reserve and other
regulatory costs 1,346 -- 1,217 --
Allowance for doubtful accounts 3,611 -- 3,316 --
Insurance accruals 2,946 -- 2,736 --
Compensation accruals 3,639 -- 2,789 --
Inventories 1,001 -- 1,204 --
Other comprehensive income 12,548 6,116 5,980 3,053
Other, net 2,851 556 2,792 2,153
- --------------------------------------------------------------------------------------------------------------
Total deferred tax assets 38,520 74,078 34,050 77,018
- --------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Depreciation and basis differences -- 99,185 -- 53,622
Minimum pension liability -- 8,093 -- 7,056
Other comprehensive income -- -- -- --
Other, net 375 -- 109 7
- --------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities 375 107,278 109 60,685
- --------------------------------------------------------------------------------------------------------------
Net deferred tax assets (liabilities) $ 38,145 $ (33,200) $ 33,941 $ 16,333
- --------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------
Alabama Gas Corporation
- --------------------------------------------------------------------------------------------------------------
(in thousands) DECEMBER 31, 2003 December 31, 2002
- --------------------------------------------------------------------------------------------------------------
CURRENT NONCURRENT Current Noncurrent
-------------------------------------------------------------
Deferred tax assets:
Pension and other costs $ -- $ 8,093 $ 823 $ 7,056
Unbilled and deferred revenue 10,578 -- 8,690 --
Enhanced stability reserve and other
regulatory costs 1,346 -- 1,217 --
Allowance for doubtful accounts 3,441 -- 3,100 --
Insurance accruals 2,503 -- 2,330 --
Compensation accruals 2,216 -- 1,680 --
Inventories 835 -- 1,171 --
Other, net 1,241 486 1,093 791
- --------------------------------------------------------------------------------------------------------------
Total deferred tax assets 22,160 8,579 20,104 7,847
- --------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Depreciation and basis differences -- 32,664 -- 21,538
Pension and other costs 4,498 -- -- --
Minimum pension liability -- 8,093 -- 7,056
Other, net 12 -- 11 --
- --------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities 4,510 40,757 11 28,594
- --------------------------------------------------------------------------------------------------------------
Net deferred tax assets (liabilities) $ 17,650 $ (32,178) $ 20,093 $ (20,747)
- --------------------------------------------------------------------------------------------------------------
The Company files a consolidated federal income tax return with all of its
subsidiaries. As of December 31, 2003,
50
the amount of minimum tax credit which can be carried forward indefinitely to
reduce future regular tax liability is $59.3 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 sheets.
Total income tax expense for the Company differed from the amount which would
have been provided by applying the statutory federal income tax rate of 35% to
earnings before taxes from continuing operations as illustrated below:
- --------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- --------------------------------------------------------------------------------------------------------------------
Income tax expense from continuing operations
at statutory federal income tax rate $ 61,038 $ 31,774 $ 157 $ 26,211
Increase (decrease) resulting from:
Nonconventional fuels tax credits -- (14,165) (3,481) (13,588)
Enhanced oil recovery tax credits (469) -- -- (25)
Deferred investment tax credits (448) (448) (112) (448)
State income taxes, net of federal income
tax benefit 5,108 2,453 41 1,518
Other, net (1,101) 774 113 (1,196)
- --------------------------------------------------------------------------------------------------------------------
Total income tax expense (benefit)
from continuing operations $ 64,128 $ 20,388 $ (3,282) $ 12,472
- --------------------------------------------------------------------------------------------------------------------
Effective income tax rate (%) 36.77 22.46 -- 16.65
- --------------------------------------------------------------------------------------------------------------------
Total 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
earnings before taxes from continuing operations as illustrated below:
- --------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- --------------------------------------------------------------------------------------------------------------------
Income tax expense from continuing operations
at statutory federal income tax rate $ 18,442 $ 15,886 $ 1,482 $ 13,812
Increase (decrease) resulting from:
Deferred investment tax credits (448) (448) (112) (448)
State income taxes, net of federal income
tax benefit 1,480 1,236 116 799
Other, net 201 1,151 61 (715)
- --------------------------------------------------------------------------------------------------------------------
Total income tax expense from continuing
operations $ 19,675 $ 17,825 $ 1,547 $ 13,448
- --------------------------------------------------------------------------------------------------------------------
Effective income tax rate (%) 37.34 39.27 36.54 34.08
- --------------------------------------------------------------------------------------------------------------------
5. EMPLOYEE BENEFIT PLANS
The Company has two defined benefit non-contributory pension plans: Plan A
covers a majority of the employees and Plan B covers employees under certain
labor union agreements. Benefits are based on years of service and final
earnings for Plan A. Plan B provides benefits based on years of service and flat
dollar amounts. The Company's policy is to use the projected unit credit
actuarial method for funding and financial reporting purposes. For its pension
plans, Energen used a September 30 measurement date.
51
The status of the plans was as follows:
- -------------------------------------------------------------------------------------------------------------
(in thousands) PLAN A
- -------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, September 30, September 30,
2003 2002 2001
-------------------------------------------------
Projected benefit obligation:
Balance at beginning of period $ 101,399 $ 92,101 $ 90,613
Service cost 3,955 3,074 899
Interest cost 6,640 6,173 1,644
Actuarial loss (gain) 15,449 6,093 (46)
Benefits paid (11,810) (6,042) (1,009)
- -------------------------------------------------------------------------------------------------------------
Balance at end of period 115,633 101,399 92,101
- -------------------------------------------------------------------------------------------------------------
Plan assets:
Fair value of plan assets at beginning of period 67,594 67,967 74,486
Actual return (loss) on plan assets 14,252 (5,331) (5,510)
Employer contributions 19,900 11,000 --
Benefits paid (11,810) (6,042) (1,009)
- -------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 89,936 67,594 67,967
- -------------------------------------------------------------------------------------------------------------
Amounts recognized in the consolidated balance sheets:
Funded status of plan (25,697) (33,805) (24,134)
Prepaid pension costs (14,087) -- --
Unrecognized actuarial loss (gain) 37,991 30,565 12,996
Unrecognized prior service cost 1,793 2,027 2,262
Unrecognized net transition obligation (asset) -- -- (196)
- -------------------------------------------------------------------------------------------------------------
Accrued pension asset (liability) $ -- $ (1,213) $ (9,072)
- -------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation $ 94,476 $ 83,871 $ 73,725
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
(in thousands) PLAN B
- -------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, September 30, September 30,
2003 2002 2001
-------------------------------------------------
Projected benefit obligation:
Balance at beginning of period $ 21,988 $ 17,945 $ 17,949
Service cost 491 396 80
Interest cost 1,417 1,422 320
Plan amendment -- 1,781 --
Actuarial loss (gain) 2,190 1,912 58
Benefits paid (1,799) (1,468) (462)
- -------------------------------------------------------------------------------------------------------------
Balance at end of period 24,287 21,988 17,945
- -------------------------------------------------------------------------------------------------------------
Plan assets:
Fair value of plan assets at beginning of period 15,688 18,420 20,666
Actual return (loss) on plan assets 2,946 (1,264) (1,784)
Employer contributions 4,000 -- --
Benefits paid (1,799) (1,468) (462)
- -------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 20,835 15,688 18,420
- -------------------------------------------------------------------------------------------------------------
Amounts recognized in the consolidated balance sheets:
Funded status of plan (3,452) (6,300) 475
Prepaid pension costs (3,609) -- --
Unrecognized actuarial loss (gain) 5,120 4,315 (481)
Unrecognized prior service cost 1,941 2,295 869
Unrecognized net transition obligation (asset) -- -- 43
Company contribution 3,200 -- --
- -------------------------------------------------------------------------------------------------------------
Accrued pension asset (liability) $ 3,200 $ 310 $ 906
- -------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation $ 24,287 $ 21,988 $ 17,945
- -------------------------------------------------------------------------------------------------------------
Weighted average rate assumptions used to determine the projected benefit
obligations at the measurement date:
52
- -------------------------------------------------------------------------------------------------------------
PLAN A
- -------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, September 30, September 30,
2003 2002 2001
-------------------------------------------------
Discount rate 6.00% 6.75% 7.50%
Rate of compensation increase 4.00% 4.50% 4.50%
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
PLAN B
- -------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, September 30, September 30,
2003 2002 2001
-------------------------------------------------
Discount rate 6.00% 6.75% 7.50%
- -------------------------------------------------------------------------------------------------------------
The components of net pension expense were:
- -------------------------------------------------------------------------------------------------------------
(in thousands) PLAN A
- -------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
2003 2002 2001 2001
-------------------------------------------------------------
Components of net periodic benefit cost:
Service cost $ 3,955 $ 3,074 $ 899 $ 2,219
Interest cost 6,640 6,173 1,643 5,458
Expected long-term return on assets (6,858) (6,145) (1,537) (5,778)
Prior service cost amortization 235 235 59 235
Actuarial loss (gain) -- -- 2 422
Net periodic benefit cost 628 -- -- --
Transition amortization -- (196) (65) (808)
- -------------------------------------------------------------------------------------------------------------
Net periodic expense $ 4,600 $ 3,141 $ 1,001 $ 1,748
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
(in thousands) PLAN B
- -------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
2003 2002 2001 2001
-------------------------------------------------------------
Components of net periodic benefit cost:
Service cost $ 491 $ 396 $ 80 $ 255
Interest cost 1,417 1,422 320 1,267
Expected long-term return on assets (1,561) (1,619) (406) (1,466)
Prior service cost amortization 354 354 59 235
Actuarial loss (gain) -- -- -- (28)
Transition amortization -- 43 14 57
- -------------------------------------------------------------------------------------------------------------
Net periodic expense $ 701 $ 596 $ 67 $ 320
- -------------------------------------------------------------------------------------------------------------
Net pension expense for Alagasco was $4,370,000 and $3,224,000 for the years
ended December 31, 2003 and 2002, respectively, $918,000 for the three months
ended December 31, 2001 and $1,812,000 for the year ended September 30, 2001.
Weighted average rate assumptions to determine net periodic benefit costs for
the period ending:
- -------------------------------------------------------------------------------------------------------------
PLAN A
- -------------------------------------------------------------------------------------------------------------
DECEMBER 31, December 31, December 31, September 30,
2003 2002 2001 2001
-------------------------------------------------------------
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%
Rate of compensation increase 4.50% 4.50% 4.50% 5.50%
- -------------------------------------------------------------------------------------------------------------
53
- -------------------------------------------------------------------------------------------------------------
PLAN B
- -------------------------------------------------------------------------------------------------------------
DECEMBER 31, December 31, December 31, September 30,
2003 2002 2001 2001
-------------------------------------------------------------
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%
- -------------------------------------------------------------------------------------------------------------
The Company's weighted-average pension plan asset allocations by asset category
were as follows:
- -------------------------------------------------------------------------------------------------------------
PLAN A
- -------------------------------------------------------------------------------------------------------------
DECEMBER 31, DECEMBER 31, DECEMBER 31,
2003 2002 2001
------------------------------------------------
Asset category:
Equity securities 64% 54% 56%
Debt securities 34% 40% 41%
Other 2% 6% 3%
- -------------------------------------------------------------------------------------------------------------
Total 100% 100% 100%
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
PLAN B
- -------------------------------------------------------------------------------------------------------------
DECEMBER 31, DECEMBER 31, DECEMBER 31,
2003 2002 2001
------------------------------------------------
Asset category:
Equity securities 71% 66% 61%
Debt securities 27% 31% 36%
Other 2% 3% 3%
- -------------------------------------------------------------------------------------------------------------
Total 100% 100% 100%
- -------------------------------------------------------------------------------------------------------------
Equity securities for Plan A and Plan B do not include the Company's common
stock.
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, 2003 and 2002, of $8 million and $21.7 million,
respectively. Alagasco established a regulatory asset of $18.1 million and $14.7
million as of December 31, 2003 and 2002, respectively, 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 $3.7 million and $4.3 million at December 31,
2003 and 2002, respectively, and the balance of $2.5 million and $1.7 million at
December 31, 2003 and 2002, respectively, was recorded as a component of
accumulated other comprehensive income, net of tax. Subsequent to December 31,
2003, Energen contributed an additional $773,000 to Plan A assets and $46,000 to
Plan B assets. The Company does not expect to make additional contributions to
Plan A or Plan B assets during 2004.
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 years ended December 31, 2003 and 2002,
the three months ended December 31, 2001 and the year ended September 30, 2001
was $386,000 $314,000, $(125,000), and $381,000, respectively. At September 30,
2003, 2002 and 2001, the accumulated post-retirement benefit obligation related
to these agreements was $15,760,000, $10,093,000 and $9,198,000, respectively,
and the projected benefit obligation was $23,203,000, $15,209,000 and
$14,082,000, respectively. An accrued post-retirement benefit liability of
$5,327,000 and $5,860,000 was recorded at December 31, 2003 and 2002,
respectively. The Company has established and funded a trust of $5.9 million and
$2.9 million as of December 31, 2003 and December 31, 2002, respectively. While
intended for payment of this benefit, the trusts' assets remain subject to the
claims of our creditors. The Company is not required to make any contributions
to the supplemental retirement plans for 2004 but is currently evaluating
possible discretionary contributions. For its supplemental retirement plans, the
Company used a September 30 measurement date.
The Company recorded a minimum pension liability for supplemental retirement
plans of $9.9 million and $4.2 million at December 31, 2003 and 2002,
respectively. A corresponding amount was recognized as an intangible
54
asset for the unrecognized prior service cost of $76,000 and $81,000 at December
31, 2003 and 2002, respectively, and the balance was recorded as a component of
accumulated other comprehensive income, net of tax, of $6.4 million and $2.6
million at December 31, 2003 and 2002, respectively.
In addition to providing pension benefits, the Company provides certain
post-retirement health care and life insurance benefits. Substantially all of
the Company's employees may become eligible for certain benefits if they reach
normal retirement age while working for the Company. The projected unit credit
actuarial method was used to determine the normal cost and actuarial liability.
For its post-retirement benefit programs, the Company used a September 30
measurement date.
The status of the post-retirement benefit programs was as follows:
- -------------------------------------------------------------------------------------------------------------
(in thousands) SALARIED EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, September 30, September 30,
2003 2002 2001
-------------------------------------------------
Projected post-retirement benefit obligation:
Balance at beginning of period $ 31,008 $ 35,888 $ 36,518
Service cost 823 831 261
Interest cost 2,045 2,120 649
Actuarial loss (gain) 7,262 (6,264) (1,274)
Benefits paid (1,663) (1,567) (266)
- -------------------------------------------------------------------------------------------------------------
Balance at end of period 39,475 31,008 35,888
- -------------------------------------------------------------------------------------------------------------
Plan assets:
Fair value of plan assets at beginning of period 24,127 30,921 36,142
Actual return (loss) on plan assets 5,064 (7,073) (5,184)
Company contribution 1,762 1,846 229
Benefits paid (1,663) (1,567) (266)
- -------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 29,290 24,127 30,921
- -------------------------------------------------------------------------------------------------------------
Amounts recognized in the consolidated balance sheets:
Funded status of plan (10,185) (6,881) (4,967)
Unrecognized actuarial loss (gain) 2,235 (1,259) (4,035)
Unrecognized net transition obligation 7,126 7,809 8,491
Company contribution 650 265 410
- -------------------------------------------------------------------------------------------------------------
Accrued benefit asset (liability) $ (174) $ (66) $ (101)
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
(in thousands) UNION EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, September 30, September 30,
2003 2002 2001
-------------------------------------------------
Projected post-retirement benefit obligation:
Balance at beginning of period $ 30,609 $ 40,077 $ 40,986
Service cost 412 807 218
Interest cost 2,010 2,800 727
Plan amendment (158) 248 --
Actuarial loss (gain) 3,256 (11,282) (1,450)
Benefits paid (2,320) (2,041) (404)
- -------------------------------------------------------------------------------------------------------------
Balance at end of period 33,809 30,609 40,077
- -------------------------------------------------------------------------------------------------------------
Plan assets:
Fair value of plan assets at beginning of period 23,895 27,954 31,917
Actual return (loss) on plan assets 5,829 (4,159) (4,628)
Company contribution 1,224 2,141 1,069
Benefits paid (2,320) (2,041) (404)
- -------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 28,628 23,895 27,954
- -------------------------------------------------------------------------------------------------------------
Amounts recognized in the consolidated balance sheets:
Funded status of plan (5,181) (6,714) (12,123)
55
Unrecognized actuarial loss (gain) (8,066) (7,869) (3,314)
Unrecognized prior service costs 63 237 --
Unrecognized net transition obligation (asset) 12,526 13,811 15,096
Company contribution 500 392 494
- -------------------------------------------------------------------------------------------------------------
Accrued benefit asset (liability) $ (158) $ (143) $ 153
- -------------------------------------------------------------------------------------------------------------
Weighted average rate assumptions used to determine post-retirement benefit
obligations at the measurement date:
- -------------------------------------------------------------------------------------------------------------
SALARIED EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, September 30, September 30,
2003 2002 2001
-------------------------------------------------
Discount rate 6.00% 6.75% 7.50%
Rate of compensation increase 4.00% 4.50% 4.50%
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
UNION EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, September 30, September 30,
2003 2002 2001
-------------------------------------------------
Discount rate 6.00% 6.75% 7.50%
- -------------------------------------------------------------------------------------------------------------
Net periodic post-retirement benefit expense included the following:
- -------------------------------------------------------------------------------------------------------------
(in thousands) SALARIED EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
2003 2002 2001 2001
-------------------------------------------------------------
Components of net periodic benefit cost:
Service cost $ 823 $ 831 $ 261 $ 1,095
Interest cost 2,045 2,120 649 2,327
Expected long-term return on assets (1,298) (1,678) (490) (1,994)
Actuarial loss (gain) -- (434) (111) (1,098)
Transition amortization 682 682 181 723
- -------------------------------------------------------------------------------------------------------------
Net periodic expense $ 2,252 $ 1,521 $ 490 $ 1,053
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
(in thousands) UNION EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
2003 2002 2001 2001
-------------------------------------------------------------
Components of net periodic benefit cost:
Service cost $ 412 $ 807 $ 218 $ 733
Interest cost 2,010 2,800 727 3,095
Expected long-term return on assets (2,102) (2,472) (720) (1,723)
Actuarial loss (gain) (283) (93) (57) (336)
Prior service cost 16 12 -- --
Transition amortization 1,285 1,285 321 1,285
- -------------------------------------------------------------------------------------------------------------
Net periodic expense $ 1,338 $ 2,339 $ 489 $ 3,054
- -------------------------------------------------------------------------------------------------------------
Net periodic post-retirement benefit expense for Alagasco was $2,902,000,
$3,493,000 for the years ended December 31, 2003 and 2002, respectively,
$905,000 for the three months ended December 31, 2001 and $3,959,000 for the
year ended September 30, 2001.
Weighted average rate assumptions to determine net periodic benefit costs for
the period ending:
56
- -------------------------------------------------------------------------------------------------------------
SALARIED EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
DECEMBER 31, December 31, December 31, September 30,
2003 2002 2001 2001
-------------------------------------------------------------
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%
Rate of compensation increase 4.50% 4.50% 4.50% 4.50%
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
UNION EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
DECEMBER 31, December 31, December 31, September 30,
2003 2002 2001 2001
-------------------------------------------------------------
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%
- -------------------------------------------------------------------------------------------------------------
Assumed post-65 health care cost trend rates used to determine the
post-retirement benefit obligation at the measurement date:
- -------------------------------------------------------------------------------------------------------------
SALARIED EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, September 30, September 30,
2003 2002 2001
-------------------------------------------------
Health care cost trend rate assumed for next year 10.00% 11.00% 7.50%
Rate to which the cost trend rate is assumed to decline 6.00% 6.00% 7.50%
Year that rate reaches ultimate rate 2008 2008 --
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
UNION EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, September 30, September 30,
2003 2002 2001
-------------------------------------------------
Health care cost trend rate assumed for next year 10.00% 11.00% 7.50%
Rate to which the cost trend rate is assumed to decline 6.00% 6.00% 7.50%
Year that rate reaches ultimate rate 2008 2008 --
- -------------------------------------------------------------------------------------------------------------
Assumed health care cost trend rates used in determining the accumulated
post-retirement benefit obligation have a significant effect on the amounts
reported. For example, increasing the weighted average health care cost trend
rate by 1 percentage point would have the following effects:
- -------------------------------------------------------------------------------------------------------------
(in thousands) SALARIED EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
1-PERCENTAGE POINT INCREASE 1-PERCENTAGE POINT DECREASE
----------------------------------------------------------
Effect on total of service and interest cost $ 331 $ (271)
Effect on net post-retirement benefit obligation $ 4,215 $ (3,330)
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
(in thousands) UNION EMPLOYEES
- -------------------------------------------------------------------------------------------------------------
1-PERCENTAGE POINT INCREASE 1-PERCENTAGE POINT DECREASE
----------------------------------------------------------
Effect on total of service and interest cost $ 200 $ (172)
Effect on net post-retirement benefit obligation $ 2,496 $ (2,070)
- -------------------------------------------------------------------------------------------------------------
The Company's weighted-average post-retirement benefit program asset allocations
by asset category were as follows:
- --------------------------------------------------------------------------------------------
SALARIED EMPLOYEES
- --------------------------------------------------------------------------------------------
DECEMBER 31, December 31, December 31,
2003 2002 2001
--------------------------------------------
Asset category:
Equity securities 91% 90% 90%
Debt securities 7% 9% 8%
Other 2% 1% 2%
- --------------------------------------------------------------------------------------------
Total 100% 100% 100%
- --------------------------------------------------------------------------------------------
57
UNION EMPLOYEES
- --------------------------------------------------------------------------------------------
UNION EMPLOYEES
- --------------------------------------------------------------------------------------------
DECEMBER 31, December 31, December 31,
2003 2002 2001
--------------------------------------------
Asset category:
Equity securities 92% 89% 90%
Debt securities 7% 8% 9%
Other 1% 3% 1%
- --------------------------------------------------------------------------------------------
Total 100% 100% 100%
- --------------------------------------------------------------------------------------------
Equity securities for the post-retirement benefit programs do not include the
Company's common stock.
The Company expects to contribute $3.7 million to post-retirement benefit
program assets during 2004.
For both defined benefit plans and other post-retirement plans, certain
financial assumptions are used in determining the Company's projected benefit
obligation. These assumptions are examined periodically by the Company, and any
required changes are reflected in the subsequent determination of projected
benefit obligations.
The Company employs a total return investment approach whereby a mix of equities
and fixed income investments are used to maximize the long-term return of plan
assets with a prudent level of risk. Risk tolerance is established through
consideration of plan liabilities, plan funded status, corporate financial
condition, and market conditions.
The Company has developed an investment strategy that focuses on asset
allocation, diversification and quality guidelines. The investment goals of the
Company are to obtain an adequate level of return to meet future obligations of
the plan by providing above average risk-adjusted returns with a risk exposure
in the mid-range of comparable funds. Because the post-retirement plans have
lower short and intermediate-term cash requirements and, accordingly, are less
impacted by short-term investment performance volatility, the Company has
elected to allocate a large percentage of investments in equity securities with
higher expected returns. Investment managers are retained by the Company to
manage separate pools of assets, and funds are allocated to such managers in
order to achieve an appropriate, diversified, and balanced asset mix.
Comparative market and peer group benchmarks are utilized to ensure that
investment mangers are performing satisfactorily.
The Company has a long-term disability plan covering most salaried employees.
The Company had expense for the years ended December 31, 2003 and 2002 of
$265,000 and $304,000, respectively. The Company had no expense for this plan in
the three months ended December 31, 2001 and in the year ended September 30,
2001.
On December 8, 2003, President Bush signed into law a bill that expands
Medicare, adding a prescription drug benefit for Medicare-eligible retirees
starting in 2006. Although the company anticipates that the benefits it pays
after 2006 will be lower as a result of the new Medicare provisions, the retiree
medical obligations and costs reported do not reflect the impact of this
legislation. Deferring the recognition of the new Medicare provisions' impact is
permitted by FASB Staff Position 106-1, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of
2003," due to open issues related to the new Medicare provisions and a lack of
authoritative accounting guidance about certain matters. The final accounting
guidance could require changes to previously reported information.
58
6. COMMON STOCK PLANS
A majority of Company employees are eligible to participate in the Energen
Employee Savings Plan (ESP) by electing to contribute a portion of their
compensation in the ESP. The Company matches a percentage of the contributions
and may make additional contributions in the form of Company common stock (new
issue or treasury shares) or funds for the purchase of Company common stock.
Prior to January 1, 2004, employees were allowed to invest their elective
contributions in Company stock. Effective January 1, 2004, the Company stock is
no longer an investment option for new elective contributions and vested
employees may diversify 100% of their ESP Company stock account into other ESP
investment options regardless of whether the Company stock was acquired through
elective contribution, Company match, Company contribution or reinvestment of
earnings. In 2003 an additional 1,000,000 shares were reserved for issuance
under the ESP resulting in total shares reserved for issuance of 1,005,239 at
December 31, 2003. Expense associated with Company contributions to the ESP was
$4,199,000 and $3,963,000 for the years ended December 31, 2003 and 2002,
respectively, $803,000 for the three months ended December 31, 2001, and
$3,597,000 for the year ended September 30, 2001.
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 Company 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. Under the Plan, 76,120 performance units were
awarded in the year ended September 30, 2001; no additional performance units
can be awarded after September 30, 2001, according to the provisions of the
Plan. 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, 117,500
performance units were awarded in the year ended December 31, 2003 and 111,760
performance units were awarded in the three months ended December 31, 2001. The
Company recorded expense of $5,653,100 and $2,136,250 for the years ended
December 31, 2003 and 2002, respectively, $722,500 for the three months ended
December 31, 2001, and $2,311,000 for the year ended September 30, 2001, 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 53,475 shares awarded in the year ended December 31, 2003,
22,775 shares awarded in the three months ended December 31, 2001 and 57,190
shares awarded in the year ended September 30, 2001. The sale or transfer of the
shares is limited during restricted periods. The Company recorded expense of
$1,076,000 and $743,000 for the years ended December 31, 2003 and 2002,
respectively, $188,000 for the three months ended December 31, 2001 and $583,000
for the year ended September 30, 2001, 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:
- ----------------------------------------------------------------------------------------------------------------
1997 STOCK INCENTIVE PLAN 1988 STOCK OPTION PLAN
- ----------------------------------------------------------------------------------------------------------------
Weighted Average Weighted Average
Shares Exercise Price Shares Exercise Price
- ----------------------------------------------------------------------------------------------------------------
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 -- -- --
59
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
- ----------------------------------------------------------------------------------------------------------------
Granted 122,080 29.71 -- --
Exercised (122,153) 21.97 (32,514) 15.16
- ----------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2003 485,420 $ 23.95 103,000 $ 14.39
- ----------------------------------------------------------------------------------------------------------------
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
Exercisable at December 31, 2003 243,000 $ 21.70 103,000 $ 14.39
- ----------------------------------------------------------------------------------------------------------------
Remaining reserved for issuance at
December 31, 2003 1,529,011 -- -- --
- ----------------------------------------------------------------------------------------------------------------
The Company adopted the fair value recognition provisions of SFAS No. 123 (as
amended), for all stock-based employee compensation on a prospective basis
effective January 1, 2003. Of the total shares granted during 2003 55,300 had
stock appreciation rights on which expense of $209,000 was recorded for the year
ended December 31, 2003. The Company recorded expense of $269,000 during the
year ended December 31, 2003, on the remaining 66,780 shares which had a
weighted average grant-date fair value of $12.10.
The following table summarizes information about options outstanding as of
December 31, 2003:
- -------------------------------------------------------------------------------------------------------------------
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-$18.81 142,120 4.59 years $10.06-$11.06 28,000 1.42 years
$27.44 104,200 6.83 years $15.00-$18.25 75,000 3.48 years
$22.63 117,020 7.83 years -- -- --
$29.71 122,080 9.08 years -- -- --
- -------------------------------------------------------------------------------------------------------------------
$18.25-$29.71 485,420 6.98 years $10.06-$18.25 103,000 2.92 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, 7,500 shares were awarded during the year ended
December 31, 2003, 6,000 shares were awarded during the three months ended
December 31, 2001 and 4,800 shares were awarded during the year ended September
30, 2001, leaving 137,139 shares reserved for issuance as of December 31, 2003.
The Company's Dividend Reinvestment and Direct Stock Purchase Plan includes a
direct stock purchase feature which allows purchases by non-shareholders. As of
December 31, 2003, 789,612 common shares were reserved under this Plan.
By resolution adopted May 25, 1994, and supplemented by a resolution adopted
April 26, 2000, the Board authorized the Company to repurchase of up to
1,782,200 shares of the Company's common stock. For the year ended December 31,
2003, the three months ended December 31, 2001 and the year ended September 30,
2001, the Company repurchased 650 shares, 54,600 shares and 91,600 shares,
respectively, pursuant to its repurchase authorization. As of December 31, 2003,
a total of 1,075,350 shares remain authorized for future repurchase. The Company
also from time to time acquires shares in connection with participant elections
under the Company's stock compensation plans. For the years ended December 31,
2003 and 2002, and the three months ended December 31, 2001, the Company
acquired 29,232 shares, 5,319 shares and 474 shares, respectively, in connection
with its stock compensation plans.
On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan)
designed to protect 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
60
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, 2003, were convertible into
362,235 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 2013.
These contracts typically contain minimum demand charge obligations on the part
of Alagasco.
ENVIRONMENTAL MATTERS: Various environmental laws and regulations apply to the
operations of Energen Resources and Alagasco. Historically, the cost of
environmental compliance has not materially affected the Company's financial
position and results of operations and is not expected to do so in the future.
However, new regulations, enforcement policies, claims for damages or other
events could result in significant unanticipated costs.
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. 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, if
any, of such costs will not materially affect the results of operations or
financial condition of Alagasco.
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 pending or threatened legal proceedings arising in the normal course of
business are in progress currently, and the Company has accrued a provision for
estimated costs.
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, Alagasco 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 $8,412,000 and $8,273,000 for the
years ended December 31, 2003 and 2002, $1,837,000 for
61
the three months ended December 31, 2001, $7,324,000 for the year ended
September 30, 2001. Minimum future rental payments required after 2003 under
leases with initial or remaining noncancelable lease terms in excess of one year
are as follows:
- --------------------------------------------------------------------------------
Years Ending December 31, (in thousands)
- --------------------------------------------------------------------------------
2004 2005 2006 2007 2008 2009 AND THEREAFTER
- --------------------------------------------------------------------------------
$ 3,388 $ 3,054 $ 2,676 $ 2,421 $ 2,093 $ 30,531
- --------------------------------------------------------------------------------
Alagasco's total payments related to leases included as operating expense,
inclusive of the sale-leaseback, were $2,602,000 and $2,362,000 for the years
ended December 31, 2003 and 2002, $587,000 for the three months ended December
31, 2001 and $2,343,000 for the year ended September 30, 2001. Minimum future
rental payments required after 2003 under leases with initial or remaining
noncancelable lease terms in excess of one year are as follows:
- --------------------------------------------------------------------------------
Years Ending December 31, (in thousands)
- --------------------------------------------------------------------------------
2004 2005 2006 2007 2008 2009 AND THEREAFTER
- --------------------------------------------------------------------------------
$ 2,209 $ 1,904 $ 1,531 $ 1,503 $ 1,483 $ 22,004
- --------------------------------------------------------------------------------
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
$564,533,000, would be $614,950,000 at December 31, 2003. The fair value of
Alagasco's fixed-rate long-term debt, including the current portion, with a
carrying value of $169,533,000, would be $188,201,000 at December 31, 2003. The
fair values were based on the market value of debt with similar maturities and
current interest rates.
Alagasco has an agreement with a financial institution whereby it may sell on an
ongoing basis, with recourse, certain installment receivables related to its
merchandising program up to a maximum of $15 million. Alagasco sold installment
receivables of $4,992,000 and $5,010,000 in the years ended December 31, 2003
and 2002, respectively, $2,120,000 in the three months ended December 31, 2001
and $5,444,000 in the year ended September 30, 2001. At December 31, 2003 and
2002, the balances of these installment receivables were $8,167,000 and
$10,566,000, 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. The fair value of these guarantees is not
significant to the Company and is recorded as a non-current other liability.
Effective February 1, 2004, Alagasco is no longer selling its installment
receivables.
Alagasco purchases gas as an agent for certain of its large commercial and
industrial customers. Alagasco has in certain instances provided
commodity-related guarantees to counterparties in order to facilitate these
agency purchases. Liabilities existing for gas delivered to customers subject to
these guarantees are included in the consolidated balance sheet. In the event
the customer for whom the guarantee was entered fails to take delivery of the
gas, Alagasco can sell such gas for the customer, with the customer liable for
any resulting loss. At December 31, 2003, the gas guaranteed had an aggregate
purchase price of $14.6 million and a market value of $16.3 million. The maximum
term over which Alagasco has guarantees outstanding is through December 2004.
PRICE RISK: The Company adopted SFAS No. 133 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 in operating revenues when
the forecasted transaction affects earnings.
The ineffective portion of a derivative's change in fair value is required to be
recognized in operating revenues
62
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 operating
revenues in the period of change.
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. In addition, Alagasco periodically 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 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.
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 in
operating revenues as originally forecasted to occur. As a result, Energen's net
income in the three-month transition period ended December 31, 2001, reflected a
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.
At December 31, 2003, the Company had current gains on the fair value of
derivatives of $0.6 million included in prepayments and other, current losses of
$34.6 million included in accounts payable and $3.5 of non-current losses
included in deferred credits and other liabilities on the consolidated balance
sheet. 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.
As of December 31, 2003, $19.6 million, net of tax, of deferred net losses on
derivative instruments recorded in accumulated other comprehensive income are
expected to be reclassified to operating revenues in 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 $1.5 million after-tax loss in 2003 for the
ineffective portion of the change in fair value of derivatives accounted for as
cash flow hedges. Also, the Company recorded an after-tax loss of $634,000 in
2003 on contracts which did not meet the definition of cash flow hedges under
SFAS No. 133. As of December 31, 2003, all of the Company's swaps and hedges met
the definition of a cash flow hedge. The Company had $13.9 million and $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, 2003 and 2002, respectively.
Energen Resources has entered into the following transactions for 2004 and
subsequent years:
- -------------------------------------------------------------------------------------------
PRODUCTION TOTAL HEDGED VOLUMES AVERAGE CONTRACT DESCRIPTION
PERIOD PRICE
- -------------------------------------------------------------------------------------------
NATURAL GAS
- -------------------------------------------------------------------------------------------
2004 15.8 Bcf $4.83 Mcf NYMEX Swaps
20.6 Bcf $4.17 Mcf Basin Specific Swaps
2.4 Bcf $4.05 - $4.44 Mcf NYMEX Collars
2005 1.2 Bcf $3.75 Mcf NYMEX Swaps
6.0 Bcf $3.96 Mcf Basin Specific Swaps
63
- -------------------------------------------------------------------------------------------
OIL
- -------------------------------------------------------------------------------------------
2004 1,428 MBbl $27.75 Bbl NYMEX Swaps
360 MBbl $27.85 Bbl West Texas Sour (WTS) Swaps
- -------------------------------------------------------------------------------------------
OIL BASIS DIFFERENTIAL
- -------------------------------------------------------------------------------------------
2004 300 MBbl ** Basis Swaps
- -------------------------------------------------------------------------------------------
NATURAL GAS LIQUIDS
- -------------------------------------------------------------------------------------------
2004 37 MMGal $0.41 Gal Liquids Swaps
- -------------------------------------------------------------------------------------------
** 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 December 31, 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
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. In accordance with SFAS No. 71, Alagasco had recorded a current
regulatory asset of $0.3 million, a current regulatory liability of $17 million
and a noncurrent regulatory liability of $8.7 million representing the fair
value of derivatives as of December 31, 2003. As of December 31, 2002, Alagasco
recorded a current regulatory liability of $16.8 million representing the fair
value of derivatives.
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 the month following 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. Energen Resources monitors the credit quality for its customers
and, in certain instances, may require credit assurances such as a deposit,
letter of credit or parent guarantee.
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.
9. RECONCILIATION OF EARNINGS PER SHARE
64
- --------------------------------------------------------------------------------------------------------------------
YEAR ENDED Year Ended
(in thousands, except per share amounts) DECEMBER 31, 2003 December 31, 2002
- --------------------------------------------------------------------------------------------------------------------
PER SHARE Per Share
INCOME SHARES AMOUNT Income Shares Amount
- --------------------------------------------------------------------------------------------------------------------
Basic EPS $110,654 35,434 $3.12 $68,639 33,605 $2.04
Effect of dilutive securities
Long-range performance shares 73 88
Stock options 201 143
Restricted stock 9 2
- --------------------------------------------------------------------------------------------------------------------
Diluted EPS $110,654 35,717 $3.10 $68,639 33,838 $2.03
- --------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------
Three Months Ended Year Ended
(in thousands, except per share amounts) December 31, 2001 September 30, 2001
- --------------------------------------------------------------------------------------------------------------------
Per Share Per Share
Income Shares Amount Income Shares Amount
- --------------------------------------------------------------------------------------------------------------------
Basic EPS $3,658 31,052 $0.12 $67,896 30,726 $2.21
Effect of dilutive securities
Long-range performance shares 96 165
Stock options 127 187
Restricted stock 2 6
- --------------------------------------------------------------------------------------------------------------------
Diluted EPS $3,658 31,277 $0.12 $67,896 31,084 $2.18
- --------------------------------------------------------------------------------------------------------------------
For the year ended December 31, 2003, the Company had no options or shares of
non-vested restricted stock that were excluded from the computation of diluted
EPS.
10. ASSET RETIREMENT OBLIGATIONS
In 2002, the Company 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 recognized a liability for the
present value of all legal obligations associated with the retirement of
tangible long-lived assets and capitalized an equal amount as a cost of the
asset as of January 1, 2002. Upon initial application of the Statement, the
Company recorded a cumulative effect of a change in accounting principle to
recognize a liability for 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. For the year ended December
31, 2002, Energen Resources recognized additional capitalized costs of $20.1
million, depreciation expense of $1.7 million, accretion expense of $1.8
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. 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 the resulting gain or
loss.
In 2002 and 2003, Energen Resources recognized activity 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
- --------------------------------------------------------------------------------
Liabilities incurred during the year ended December 31, 2003 1,139
Liabilities settled during the year ended December 31, 2003 (3,750)
Accretion expense 1,891
- --------------------------------------------------------------------------------
Balance of ARO as of December 31, 2003 $ 26,515
- --------------------------------------------------------------------------------
The Company's gas distribution system operates under various property easement
agreements primarily related to
65
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 to be operated
in perpetuity and historical abandonment costs resulting from such easement
agreements have been de minimis, no asset retirement obligation has been
recorded. Alagasco accrues removal costs on certain gas distribution assets over
the useful lives of its property, plant and equipment through depreciation
expense in accordance with rates approved by the APSC. In 2003, Alagasco revised
its balance sheet presentation to reclassify the accrual for net removal costs
from accumulated depreciation to a regulatory liability in accordance with SFAS
No. 71, "Accounting for the Effects of Certain Types of Regulation." As a
result, regulatory liabilities increased for accumulated asset removal costs by
$103.7 million, $94.7 million and $87.5 million for December 31, 2003, 2002 and
2001, respectively.
11. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental information concerning Energen's cash flow activities is as
follows:
- ------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- ------------------------------------------------------------------------------------------------------------------------
Interest paid, net of amount capitalized $39,963 $43,085 $11,418 $42,905
Income taxes paid $10,929 $ 9,838 $ 4,261 $11,636
Noncash investing activities:
First Permian, L.L.C. stock issuance $ -- $72,891 $ -- $ --
Capitalized depreciation $ 123 $ 223 $ 51 $ 243
Allowance for funds used during construction $ 1,529 $ 1,336 $ 122 $ 2,098
- ------------------------------------------------------------------------------------------------------------------------
Under SFAS No. 143, the Company recorded a non-cash adjustment for accretion
expense of $1.9 million during 2003. During 2002, additional capitalized 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 were recorded, all of which are non-cash adjustments concerning
Energen's cash flow activities.
Supplemental information concerning Alagasco's cash flow activities is as
follows:
- ------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- ------------------------------------------------------------------------------------------------------------------------
Interest paid, net of amount capitalized $12,477 $14,012 $5,666 $12,154
Income taxes paid $12,754 $15,519 $9,425 $18,318
Noncash investing activities:
Capitalized depreciation $ 123 $ 223 $ 51 $ 243
Allowance for funds used during construction $ 1,529 $ 1,336 $ 122 $ 2,098
- ------------------------------------------------------------------------------------------------------------------------
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," which 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 flows 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. The results of
operations for held-for-sale properties are reclassified and reported as
discontinued operations for prior periods in accordance with SFAS No. 144.
Energen Resources may, in the ordinary course of business, be involved in the
sale of developed or undeveloped properties. All assets held-for-sale must be
reported at the lower of the carrying amount or fair value.
66
Accordingly, during 2003, Energen Resources recorded a pre-tax writedown to fair
value based upon expected market value of $10.4 million on certain non-strategic
gas properties located in the Gulf Coast region. These properties were
subsequently sold during 2003 for a pre-tax gain of $0.4 million. The gain on
disposals for the year ended December 31, 2003, totaled $9.4 million primarily
due to sales of properties in the San Juan Basin. As of December 31, 2003, the
Company had no properties classified as held-for-sale. During 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,
totaled $3.7 million largely due to sales of property located in the Permian
Basin. In 2001, prior to adopting SFAS No. 144, a pre-tax gain of $0.8 million
was recorded in operating revenues from continuing operations for certain
non-strategic property sales.
The following are the results of operations from discontinued operations:
- -------------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands, except per share data) 2003 2002 2001 2001
- -------------------------------------------------------------------------------------------------------------------------------
Oil and gas revenues $ 3,586 $ 10,362 $ 3,696 $22,157
- -------------------------------------------------------------------------------------------------------------------------------
Pretax income (loss) from discontinued
operations $ 1,594 $ (133) $ (115) $ 8,983
Income tax expense (benefit) 621 (53) (43) 3,504
- -------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) FROM DISCONTINUED OPERATIONS 973 (80) (72) 5,479
- -------------------------------------------------------------------------------------------------------------------------------
Impairment charge on held-for-sale property (10,404) (2,815) -- --
Gain on disposal 9,448 3,706 -- --
Income tax expense (benefit) (372) 348 -- --
- -------------------------------------------------------------------------------------------------------------------------------
GAIN (LOSS) ON DISPOSAL (584) 543 -- --
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME (LOSS) FROM DISCONTINUED
OPERATIONS $ 389 $ 463 $ (72) $ 5,479
- -------------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER AVERAGE COMMON SHARE
Income (Loss) from Discontinued Operations $ 0.03 $ -- $ -- $ 0.17
- -------------------------------------------------------------------------------------------------------------------------------
Gain (Loss) on Disposal (0.02) 0.02 -- --
- -------------------------------------------------------------------------------------------------------------------------------
Total Income from Discontinued Operations $ 0.01 $ 0.02 $ -- $ 0.17
- -------------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS PER AVERAGE COMMON SHARE
Income (Loss) from Discontinued Operations $ 0.03 $ -- $ -- $ 0.18
Gain (Loss) on Disposal (0.02) 0.02 -- --
- -------------------------------------------------------------------------------------------------------------------------------
Total Income from Discontinued Operations $ 0.01 $ 0.02 $ -- $ 0.18
- -------------------------------------------------------------------------------------------------------------------------------
13. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
The Company's business is seasonal in character. The following data summarizes
quarterly operating results. The summarized quarterly information may differ
from amounts previously reported due to changes in the classification of
properties reported as discontinued operations as required by SFAS No. 144 (see
Note 12).
- -------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2003
----------------------------
(in thousands, except per share amounts) First Second Third Fourth
- -------------------------------------------------------------------------------------------------------------------
Operating revenues $309,658 $184,030 $146,141 $202,392
Operating income $ 96,614 $ 50,512 $ 29,356 $ 43,296
Income from continuing operations before cumulative
effect of change in accounting principle $ 53,323 $ 24,459 $ 11,457 $ 21,026
67
Net income $ 54,581 $ 23,347 $ 11,896 $ 20,830
Diluted earnings per average common share
Continuing operations $ 1.52 $ 0.69 $ 0.32 $ 0.58
Net income $ 1.56 $ 0.66 $ 0.33 $ 0.57
Basic earnings per average common share
Continuing operations $ 1.54 $ 0.70 $ 0.32 $ 0.58
Net income $ 1.57 $ 0.67 $ 0.33 $ 0.58
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2002
----------------------------
(in thousands, except per share amounts) First Second Third Fourth
- -------------------------------------------------------------------------------------------------------------------
Operating revenues $241,413 $137,844 $114,844 $174,450
Operating income $ 61,252 $ 25,762 $ 13,137 $ 35,624
Income from continuing operations before cumulative
effect of change in accounting principle $ 39,042 $ 12,771 $ 97 $ 18,486
Net income $ 36,682 $ 12,744 $ 127 $ 19,086
Diluted earnings per average common share
Continuing operations $ 1.24 $ 0.37 $ 0.00 $ 0.53
Net income $ 1.17 $ 0.37 $ 0.00 $ 0.55
Basic earnings per average common share
Continuing operations $ 1.25 $ 0.37 $ 0.00 $ 0.53
Net income $ 1.18 $ 0.37 $ 0.00 $ 0.55
- -------------------------------------------------------------------------------------------------------------------
Alagasco's business is seasonal in character and influenced by weather
conditions. The following data summarizes Alagasco's quarterly operating
results.
- -------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2003
----------------------------
(in thousands, except per share amounts) First Second Third Fourth
- -------------------------------------------------------------------------------------------------------------------
Operating revenues $221,139 $ 94,248 $ 58,147 $115,565
Operating income (loss) $ 57,200 $ 6,988 $ (9,575) $ 12,235
Net income (loss) $ 33,447 $ 2,135 $ (7,781) $ 5,216
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2002
----------------------------
(in thousands, except per share amounts) First Second Third Fourth
- -------------------------------------------------------------------------------------------------------------------
Operating revenues $196,524 $ 75,709 $ 50,225 $101,973
Operating income (loss) $ 52,811 $ 4,721 $ (8,907) $ 10,745
Net income (loss) $ 30,542 $ 964 $ (7,700) $ 3,758
- -------------------------------------------------------------------------------------------------------------------
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.
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 purchase of assets
had occurred at the beginning of each period presented. The pro forma
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 seller, after giving
effect to the issuance of 3,043,479 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.
68
- ------------------------------------------------------------------------------------------------------------
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 $675,156 $151,406 $787,629
Income from continuing operations before cumulative effect
of change in accounting principle $ 71,529 $ 4,459 $ 61,083
Net income $ 69,772 $ 4,387 $ 66,562
Diluted earnings per average common share $ 2.06 $ 0.14 $ 2.14
Basic earnings per average common share $ 2.08 $ 0.14 $ 2.17
- ------------------------------------------------------------------------------------------------------------
15. REGULATORY ASSETS AND LIABILITES
The following table details regulatory asset and liabilities on the consolidated
balance sheets:
Energen Corporation
- -----------------------------------------------------------------------------------------------------
(in thousands) DECEMBER 31, 2003 December 31, 2002
- -----------------------------------------------------------------------------------------------------
CURRENT NONCURRENT Current Noncurrent
- -----------------------------------------------------------------------------------------------------
Regulatory assets:
Pension asset $ -- $ 18,082 $ -- $ 14,744
Risk management activities 251 -- -- --
- -----------------------------------------------------------------------------------------------------
Total regulatory assets $ 251 $ 18,082 $ -- $ 14,744
- -----------------------------------------------------------------------------------------------------
Regulatory liabilities:
Enhanced stability reserve $ 3,481 $ -- $ 2,963 $ --
Gas supply adjustment 4,903 -- 3,845 --
Risk management activities 17,025 8,650 16,750 --
RSE 2,619 -- 256 --
Unbilled service margin 26,118 -- 17,370 --
Asset removal costs, net -- 103,727 -- 94,751
Other -- 1,050 -- 1,468
- -----------------------------------------------------------------------------------------------------
Total regulatory liabilities $ 54,146 $113,427 $ 41,184 $ 96,219
- -----------------------------------------------------------------------------------------------------
16. EQUITY AND DEBT OFFERINGS
In July 2003, Energen completed the issuance of 1,000,000 shares of common stock
through the periodic draw-down of shares in a shelf registration. The sale of
shares began May 9, 2003, and concluded on July 16, 2003, generating net
proceeds of $32.1 million. In October 2003, Energen issued $50 million of
long-term debt due October 1, 2013. The 5% coupon notes were priced at 99.557
percent to yield 5.057 percent. These proceeds were be used for general
corporate purposes and to repay a portion of short-term debt incurred to finance
the oil and gas property acquisition program of Energen Resources.
17. TRANSACTIONS WITH RELATED PARTIES
Alagasco purchased natural gas from affiliates of $3,195,000 and $1,820,000 for
the years ended December 31, 2003 and 2002, $375,000 for the three months ended
December 31, 2001 and $5,254,000 for the year ended September 30, 2001. These
amounts are included in gas purchased for resale. Alagasco had net payables to
affiliates of $37,290,000 and $1,432,000 at December 31, 2003 and December 31,
2002, respectively.
18. OTHER INCOME AND EXPENSE
69
The following table details Energen's other income and expense amounts on the
consolidated income statements:
- -----------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -----------------------------------------------------------------------------------------------------------
Allowance for funds used during construction $ 948 $ 1,336 $ 122 $ 2,098
Merchandise revenues 7,696 14,155 4,226 14,535
Other 100 153 6 192
- -----------------------------------------------------------------------------------------------------------
Total other income $ 8,744 $15,644 $ 4,354 $16,825
- -----------------------------------------------------------------------------------------------------------
Cost of goods sold $ 8,549 $10,215 $ 3,181 $10,136
Other merchandise expense 1,428 4,888 1,204 4,756
- -----------------------------------------------------------------------------------------------------------
Total other expense $ 9,977 $15,103 $ 4,385 $14,892
- -----------------------------------------------------------------------------------------------------------
The following table details Alagasco's other income and expense amounts on the
income statements:
- -----------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -----------------------------------------------------------------------------------------------------------
Merchandise revenues $ 5,080 $ 5,520 $ 1,596 $ 5,978
- -----------------------------------------------------------------------------------------------------------
Total other income $ 5,080 $ 5,520 $ 1,596 $ 5,978
- -----------------------------------------------------------------------------------------------------------
Cost of goods sold $ 5,142 $ 2,702 $ 946 $ 3,051
Other merchandise expense 127 3,578 892 3,534
- -----------------------------------------------------------------------------------------------------------
Total other expense $ 5,269 $ 6,280 $ 1,838 $ 6,585
- -----------------------------------------------------------------------------------------------------------
The sale of merchandise inventory items are reflected in other income and
expense. In 2003, a key supplier of certain merchandise inventories ended its
business relationship with the Company. Alagasco no longer participates in
direct sales of natural gas merchandise effective February 1, 2004. Alagasco
continues to work closely with various contractors and retail companies to meet
the merchandise requirements of its customers.
19. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other
Intangible Assets," were issued by the FASB in June 2001 and became effective on
July 1, 2001, and January 1, 2002, respectively. SFAS No. 141 requires all
business combinations initiated after June 30, 2001, to be accounted for using
the purchase method and SFAS No. 142 establishes new guidelines in accounting
for goodwill and other intangible assets. Under SFAS No. 142, goodwill and
certain intangible assets that have indefinite useful lives are not amortized,
but rather are reviewed annually for impairment. The appropriate application of
SFAS No. 141 and SFAS No. 142 to oil and gas mineral rights held under lease and
other contractual arrangements representing the right to extract such reserves
is currently being considered. One interpretation relative to these standards is
that oil and gas mineral rights for both undeveloped and developed leaseholds
could be classified separately from oil and gas properties as intangible assets
on the balance sheet, rather than as a part of oil and gas properties as
currently recorded. In addition, the disclosures required by SFAS No. 141 and
SFAS No. 142 relative to intangible assets would be included in the notes to the
financial statements. The Company anticipates that this interpretation of SFAS
No. 141 and SFAS No. 142 would only affect balance sheet classifications of oil
and gas leaseholds. Results of operations and cash flows are not anticipated to
be affected, since these oil and gas mineral rights held under lease and other
contractual arrangements representing the right to extract such reserves would
continue to be amortized in accordance with
SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing
Companies." The Company will continue to evaluate the impact of the application
of these standards as further guidance is provided.
70
The Company adopted the fair value recognition provisions of SFAS No. 123 (as
amended), prospectively for all stock-based employee compensation effective as
of January 1, 2003. Awards under the Company's plan vest over periods ranging
from one to four years; therefore, the cost related to stock-based employee
compensation included in the determination of net income is less than that which
would have been recognized if the fair value method had been applied to all
awards since the original effective date of SFAS No. 123.
In December 2003, the FASB revised SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits - an amendment of FASB Statements No.
87, 88 and 106." The revised Statement added additional disclosures relating to
the assets, obligations, cash flows and net periodic benefit cost of defined
benefit pension plans and other postretirement plans and is effective for
financial statements with fiscal years ending after December 15, 2003, with an
exception for the disclosure of estimated future benefit payments effective for
fiscal years ending after June 15, 2004. The Company has incorporated within
this report the additional required disclosures (See Note 5).
20. OIL AND GAS OPERATIONS (UNAUDITED)
The following schedules detail historical financial data of the 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
- --------------------------------------------------------------------------------------------------
(in thousands) DECEMBER 31, 2003 December 31, 2002
- --------------------------------------------------------------------------------------------------
Proved $1,191,528 $1,091,536
Unproved 5,812 11,936
- --------------------------------------------------------------------------------------------------
Total capitalized costs 1,197,340 1,103,472
Accumulated depreciation, depletion, and amortization 310,368 269,616
- --------------------------------------------------------------------------------------------------
Capitalized costs, net $ 886,972 $ 833,856
- --------------------------------------------------------------------------------------------------
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:
71
- -----------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -----------------------------------------------------------------------------------------------------------------------
Property acquisition:
Proved $ 40,219 $173,984 $ 238 $ 33,764
Unproved 267 10,193 81 552
Exploration 468 527 339 1,734
Development 122,094 122,494 24,757 103,574
- -----------------------------------------------------------------------------------------------------------------------
Total costs incurred $163,048 $307,198 $ 25,415 $139,624
- -----------------------------------------------------------------------------------------------------------------------
RESULTS OF CONTINUING OPERATIONS: The following table sets forth results of the
Company's oil and gas continuing operations:
- -----------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -----------------------------------------------------------------------------------------------------------------------
Gross revenues $354,816 $245,397 $ 50,613 $208,592
Production (lifting costs) 95,651 75,395 14,861 72,106
Exploration expense 1,053 3,595 827 4,206
Depreciation, depletion and amortization 78,241 66,594 14,986 49,563
Accretion expense 1,820 1,890 -- --
Income tax expense 66,419 23,102 4,103 15,688
- -----------------------------------------------------------------------------------------------------------------------
Results of continuing operation from producing
activities $111,632 $ 74,821 $ 15,836 $ 67,029
- -----------------------------------------------------------------------------------------------------------------------
AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE FROM CONTINUING
OPERATIONS
- -----------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
2003 2002 2001 2001
- -----------------------------------------------------------------------------------------------------------------------
Average sales price including the effects of hedging:
Gas (Mcf) $ 4.25 $ 3.17 $ 2.99 $ 3.01
Oil (per barrel) $ 25.56 $ 24.13 $ 24.01 $ 23.43
Natural gas liquids (per barrel) $ 16.32 $ 12.77 $ 10.01 $ 17.57
Average sales price excluding the effects of hedging:
Gas (Mcf) $ 4.97 $ 2.96 $ 2.34 $ 4.85
Oil (per barrel) $ 29.19 $ 24.82 $ 19.52 $ 27.42
Natural gas liquids (per barrel) $ 18.40 $ 12.77 $ 10.01 $ 17.57
Average production (lifting) cost (per Mcfe) $ 1.12 $ 1.01 $ 0.88 $ 1.13
Average production tax (per Mcfe) $ 0.32 $ 0.25 $ 0.20 $ 0.36
Average depreciation rate (per Mcfe) $ 0.92 $ 0.89 $ 0.89 $ 0.78
- -----------------------------------------------------------------------------------------------------------------------
DRILLING ACTIVITY: The following table sets forth the total number of net
productive and dry exploratory and development wells drilled:
72
- ----------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
2003 2002 2001 2001
- ----------------------------------------------------------------------------------------
Exploratory:
Productive 0.7 0.1 0.3 0.1
Dry 0.3 0.1 -- 1.3
- ----------------------------------------------------------------------------------------
Total 1.0 0.2 0.3 1.4
- ----------------------------------------------------------------------------------------
Development:
Productive 194.2 145.9 23.8 90.7
Dry 3.0 4.3 -- --
- ----------------------------------------------------------------------------------------
Total 197.2 150.2 23.8 90.7
- ----------------------------------------------------------------------------------------
As of December 31, 2003, the Company was participating in the drilling of 6
gross development wells, with the Company's interest equivalent to 4.21 wells.
PRODUCTIVE WELLS AND ACREAGE: The following table sets forth the total gross and
net productive gas and oil wells as of December 31, 2003, and developed and
undeveloped acreage as of the latest practicable date prior to year-end:
- --------------------------------------------------------------------------------
Gross Net
- --------------------------------------------------------------------------------
Gas Wells 3,388 1,747
Oil Wells 2,233 996
- --------------------------------------------------------------------------------
Developed Acreage 740,786 451,319
Undeveloped Acreage 101,034 55,439
- --------------------------------------------------------------------------------
There were 44 wells with multiple completions in 2003. 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.
Estimates of physical quantities of oil and gas proved reserves were determined
by Company engineers. Ryder Scott Company, Miller and Lents, Ltd., and T. Scott
Hickman and Associates, Inc., independent oil and gas reservoir engineers, have
reviewed the estimates of proved reserves of natural gas, oil and natural gas
liquids that the Company has attributed to its net interests in oil and gas
properties as of December 31, 2003. Ryder Scott Company reviewed the reserve
estimates for the Black Warrior Basin and substantially all of the Permian Basin
reserves. Miller and Lents, Ltd. reviewed the reserves for the north
Louisiana/east Texas regions. T. Scott Hickman and Associates, Inc. reviewed the
reserves for the San Juan Basin. The independent reservoir engineers have issued
reports covering approximately 97 percent of the Company's ending proved
reserves indicating that in their judgment the estimates are reasonable in the
aggregate.
73
- ---------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2003 Gas MMcf Oil MBbl NGL MBbl
- ---------------------------------------------------------------------------------------------
Proved reserves at beginning of period 803,748 49,833 26,697
Revisions of previous estimates (10,847) 1,237 (826)
Purchases 93,700 1,172 --
Discoveries and other additions 80,124 5,051 4,068
Production (55,796) (3,458) (1,602)
Sales (24,622) (1,307) (1,092)
- ---------------------------------------------------------------------------------------------
Proved reserves at end of period 886,307 52,528 27,245
- ---------------------------------------------------------------------------------------------
Proved developed reserves at end of period 714,866 40,802 23,552
- ---------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------
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
- ---------------------------------------------------------------------------------------------
During 2003, Energen Resources sold approximately 39 Bcfe of proved reserves,
recording a net pre-tax loss of $1 million, which includes a $10.4 million
writedown on assets held-for-sale and subsequently sold during the year
partially offset by gains on property sales of $9.4 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, 2003, December 31, 2002, December 31, 2001, and September 30, 2001, the
Company had a deferred hedging loss of $35.6 million and $17.2 million, and a
deferred hedging gain of $15.2 million and $25.7 million, respectively, all of
which are excluded from the calculation of standardized measure of future net
cash flows.
74
- -------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -------------------------------------------------------------------------------------------------------------------------
Future gross revenues $ 7,211,830 $ 5,455,802 $ 2,181,148 $ 1,672,436
Future production costs 2,189,464 1,754,700 829,968 693,817
Future development costs 204,513 183,818 114,317 83,781
- -------------------------------------------------------------------------------------------------------------------------
Future net cash flows before income taxes 4,817,853 3,517,284 1,236,863 894,838
Future income tax expense 1,609,324 1,100,392 265,611 124,803
- -------------------------------------------------------------------------------------------------------------------------
Future net cash flows after income taxes 3,208,529 2,416,892 971,252 770,035
Discount at 10% per annum 1,635,450 1,172,635 399,810 272,493
- -------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net
cash flows relating to proved oil and gas
reserves $ 1,573,079 $ 1,244,257 $ 571,442 $ 497,542
- -------------------------------------------------------------------------------------------------------------------------
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 Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- -------------------------------------------------------------------------------------------------------------------------
Balance at beginning of year $ 1,244,257 $ 571,442 $ 497,542 $ 1,105,265
- -------------------------------------------------------------------------------------------------------------------------
Revisions to reserves proved in prior years:
Net changes in prices, production costs
and future development costs 365,816 658,956 100,710 (1,015,900)
Net changes due to revisions in
quantity estimates (14,804) (8,380) 49,579 (81,076)
Development costs incurred,
previously estimated 80,878 49,418 8,812 50,768
Accretion of discount 124,426 57,144 11,398 144,266
Other 39,134 (8,669) (24,012) 95,165
- -------------------------------------------------------------------------------------------------------------------------
Total revisions 595,450 748,469 146,487 (806,777)
New field discoveries and extensions, net
of future production and development costs 200,880 213,625 5,562 33,685
Sales of oil and gas produced, net of
production costs (311,189) (162,151) (23,699) (220,220)
Purchases 74,201 218,799 20 32,811
Sales (48,107) (14,203) (2,271) (26,256)
Net change in income taxes (182,413) (331,724) (52,199) 379,034
- -------------------------------------------------------------------------------------------------------------------------
Net change in standardized measure
of discounted future net cash flows 328,822 672,815 73,900 (607,723)
- -------------------------------------------------------------------------------------------------------------------------
Balance at end of year $ 1,573,079 $ 1,244,257 $ 571,442 $ 497,542
- -------------------------------------------------------------------------------------------------------------------------
75
21. INDUSTRY SEGMENT INFORMATION
The Company is principally engaged in two business segments: the acquisition,
development, exploration and production of oil and gas in the continental United
States (oil and gas operations) and the purchase, distribution and sale of
natural 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 prior years' financial
statements to the current year presentation.
- --------------------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- --------------------------------------------------------------------------------------------------------------------------------
Operating revenues from continuing operations
Oil and gas operations $ 353,122 $ 244,120 $ 46,954 $ 208,954
Natural gas distribution 489,099 424,431 96,678 553,862
- --------------------------------------------------------------------------------------------------------------------------------
Total $ 842,221 $ 668,551 $ 143,632 $ 762,816
- --------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) from continuing operations
Oil and gas operations $ 153,591 $ 76,286 $ 3,496 $ 66,416
Natural gas distribution 66,848 59,370 8,034 50,288
- --------------------------------------------------------------------------------------------------------------------------------
Subtotal $ 220,439 $ 135,656 $ 11,530 $ 116,704
Eliminations and corporate expenses (2,551) (1,700) (417) (1,678)
- --------------------------------------------------------------------------------------------------------------------------------
Total $ 217,888 $ 133,956 $ 11,113 $ 115,026
- --------------------------------------------------------------------------------------------------------------------------------
Depreciation, depletion and amortization expense
from continuing operations
Oil and gas operations $ 79,687 $ 68,009 $ 15,317 $ 50,907
Natural gas distribution 37,171 33,682 8,151 30,933
- --------------------------------------------------------------------------------------------------------------------------------
Total $ 116,858 $ 101,691 $ 23,468 $ 81,840
- --------------------------------------------------------------------------------------------------------------------------------
Interest expense
Oil and gas operations $ 28,577 $ 29,635 $ 7,042 $ 30,244
Natural gas distribution 13,967 14,557 3,680 12,316
- --------------------------------------------------------------------------------------------------------------------------------
Subtotal $ 42,544 $ 44,192 $ 10,722 $ 42,560
Eliminations and other (282) (479) (88) (490)
- --------------------------------------------------------------------------------------------------------------------------------
Total $ 42,262 $ 43,713 $ 10,634 $ 42,070
- --------------------------------------------------------------------------------------------------------------------------------
Income tax expense (benefit) from continuing operations
Oil and gas operations $ 46,616 $ 3,820 $ (4,741) $ (611)
Natural gas distribution 19,675 17,825 1,547 13,448
- --------------------------------------------------------------------------------------------------------------------------------
Subtotal $ 66,291 $ 21,645 $ (3,194) $ 12,837
Other (2,163) (1,257) (88) (365)
- --------------------------------------------------------------------------------------------------------------------------------
Total $ 64,128 $ 20,388 $ (3,282) $ 12,472
- --------------------------------------------------------------------------------------------------------------------------------
Capital expenditures
Oil and gas operations $ 163,338 $ 305,476 $ 25,052 $ 136,886
Natural gas distribution 57,906 65,815 12,873 56,090
Other -- 5 -- 60
- --------------------------------------------------------------------------------------------------------------------------------
Total $ 221,244 $ 371,296 $ 37,925 $ 193,036
- --------------------------------------------------------------------------------------------------------------------------------
Identifiable assets
Oil and gas operations $ 959,815 $ 926,839 $ 687,776 $ 716,043
Natural gas distribution 797,693 715,330 651,211 606,808
- --------------------------------------------------------------------------------------------------------------------------------
Subtotal $1,757,508 $1,642,169 $1,338,987 $1,322,851
Eliminations and other 23,924 843 3,359 (8,966)
- --------------------------------------------------------------------------------------------------------------------------------
Total $1,781,432 $1,643,012 $1,342,346 $1,313,885
- --------------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment, net
Oil and gas operations $ 891,682 $ 838,526 $ 620,305 $ 617,592
Natural gas distribution 541,769 512,849 472,659 466,207
Other -- 179 237 253
- --------------------------------------------------------------------------------------------------------------------------------
Total $1,433,451 $1,351,554 $1,093,201 $1,084,052
- --------------------------------------------------------------------------------------------------------------------------------
76
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
ENERGEN CORPORATION
- ------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- ------------------------------------------------------------------------------------------------------------------
ALLOWANCE FOR DOUBTFUL ACCOUNTS
BALANCE AT BEGINNING OF YEAR $ 8,874 $ 11,783 $ 10,031 $ 6,681
- ------------------------------------------------------------------------------------------------------------------
Additions:
Charged to income 5,820 5,482 1,819 7,953
Recoveries and adjustments (616) (495) 139 (901)
- ------------------------------------------------------------------------------------------------------------------
Net additions 5,204 4,987 1,958 7,052
- ------------------------------------------------------------------------------------------------------------------
Less uncollectible accounts written off (4,226) (7,896) (206) (3,702)
- ------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR $ 9,852 $ 8,874 $ 11,783 $ 10,031
- ------------------------------------------------------------------------------------------------------------------
ALABAMA GAS CORPORATION
- ------------------------------------------------------------------------------------------------------------------
Three Months
YEAR ENDED Year Ended Ended Year Ended
DECEMBER 31, December 31, December 31, September 30,
(in thousands) 2003 2002 2001 2001
- ------------------------------------------------------------------------------------------------------------------
ALLOWANCE FOR DOUBTFUL ACCOUNTS
BALANCE AT BEGINNING OF YEAR $ 8,200 $ 11,100 $ 9,500 $ 5,800
- ------------------------------------------------------------------------------------------------------------------
Additions:
Charged to income 5,668 5,410 1,816 7,799
Recoveries and adjustments (601) (565) (38) (452)
- ------------------------------------------------------------------------------------------------------------------
Net additions 5,067 4,845 1,778 7,347
- ------------------------------------------------------------------------------------------------------------------
Less uncollectible accounts written off (4,167) (7,745) (178) (3,647)
- ------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR $ 9,100 $ 8,200 $ 11,100 $ 9,500
- ------------------------------------------------------------------------------------------------------------------
77
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
A. Our chief executive officer and chief financial officer have evaluated the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation they have concluded that
our disclosure controls and procedures are effective at a reasonable assurance
level.
B. Our chief executive officer and chief financial officer have concluded that
during the period covered by this report there were no changes in our internal
controls that materially affected or are reasonably likely to materially affect
our internal control over financial reporting.
78
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 28, 2004. The proxy statement will be filed on or about March
29, 2004.
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 28, 2004.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
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 28, 2004.
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 28, 2004.
C. SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The information regarding securities authorized for issuance under equity
compensation plans is included in Part 2 under Item 5.
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 28, 2004.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information regarding Principal Accountant Fees and Services is incorporated
herein by reference from Energen's definitive proxy statement for the Annual
Meeting of Shareholders to be held April 28, 2004.
79
PART IV
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 January 15, 2003, reporting Drayton Nabers, Jr., former
chairman and chief executive officer of Protective Life Corporation,
resigned from the Board of Directors of Energen Corporation effective
January 15, 2003.
Form 8-K/A dated January 24, 2003, reporting Drayton Nabers, Jr., former
chairman and chief executive officer of Protective Life Corporation,
resigned from the Board of Directors of Energen Corporation effective
January 15, 2003.
Form 8-K dated April 24, 2003, reporting Energen and Alagasco issued a
press release announcing financial results for the first quarter of 2003.
Form 8-K dated July 18, 2003, reporting the sale of 1,000,000 shares of
Energen common stock.
Form 8-K dated July 23, 2003, reporting Energen and Alagasco issued a
press release announcing financial results for the second quarter of 2003.
Form 8-K dated October 3, 2003, reporting Energen and Alagasco issued a
series of 5% Notes due October 3, 2013. The aggregate principal amount of
notes offered was $50,000,000.
Form 8-K dated October 29, 2003, reporting Energen and Alagasco issued a
press release announcing financial results for the third quarter of 2003.
Form 8-K dated December 10, 2003, reporting Energen and Alagasco issued a
press release announcing financial results earnings guidance for 2004, the
election of David W. Wilson as a Director of Energen Corporation effective
January 1, 2004 and Wm. Michael Warren, Jr., Chairman of the Board and
Chief Executive Officer of Energen Corporation adopted a Securities
Trading Plan. Mr. Warren adopted the plan pursuant to Rule 10b5-1 of the
Securities Exchange Act of 1934 and during an open trading window.
80
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 October 30, 2002)
which was filed as Exhibit 4(c) to Energen's Registration Statement
on Form S-8 (Registration No. 33-46641)
*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 October 30,
2002).
*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(b)(iv) Officers' Certificate, dated October 3, 2003, pursuant to Section
301 of the Energen 1996 Indenture setting forth the terms of the 5%
Notes due October 1, 2013, which was filed as Exhibit 4 to Energen's
Current Report on Form 8-K, dated October 3, 2003 (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)
81
*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
*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 Service Agreement Under Rate Schedule FT (No. 866940)
between Southern Natural Gas Company and Alabama Gas Corporation
which was file as Exhibit 10(d) to Energen's Annual Report on Form
10-K for the year ended September 30, 1993 (File No. 1-7810)
*10(d) Form of Service Agreement Under Rate Schedule IT (No. 790420),
between Southern Natural Gas Company and Alabama Gas Corporation
which was filed as Exhibit 10(b) to Energen's Annual Report on Form
10-K for the year ended September 30, 1993 (File No. 1-7810)
10(e) Service Agreement between Transcontinental Gas Pipeline Corporation
and Transco Energy Marketing Company as Agent for Alabama Gas
Corporation, dated August 1, 1991.
*10(f) 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(g) 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(h) 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(i) 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(j) 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(k) 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(l) 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)
82
*10(m) 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(n) 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(o) 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)
*10(p) 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(q) 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(a) Consent of Independent Accountants (PricewaterhouseCoopers LLP)
23(b) Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott
Company)
23(c) Consent of Independent Oil and Gas Reservoir Engineers (Miller and
Lents, Ltd.)
23(d) Consent of Independent Oil and Gas Reservoir Engineers (T. Scott
Hickman and Associates, Inc.)
31(a) Certification of Chief Executive Officer pursuant to Rule 13a-14(a)
or 15d-14(a)
31(b) Certification of Chief Financial Officer pursuant to Rule 13a-14(a)
or 15d-14(a)
32 Certification pursuant to Section 1350
*Incorporated by reference
83
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 12, 2004 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
84
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 12, 2004 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 12, 2004 By /s/ Geoffrey C. Ketcham
- -------------- --------------------------------------
Geoffrey C. Ketcham
Executive Vice President, Chief
Financial Officer and Treasurer of
Energen and Alabama Gas Corporation
March 12, 2004 By /s/ Grace B. Carr
- -------------- --------------------------------------
Grace B. Carr
Vice President and Controller of
Energen
March 12, 2004 By /s/ Paula H. Rushing
- -------------- --------------------------------------
Paula H. Rushing
Vice President-Finance of Alabama Gas
Corporation
March 12, 2004 By /s/ Julian W. Banton
- -------------- --------------------------------------
Julian W. Banton
Director
March 12, 2004 By /s/ James S. M. French
- -------------- --------------------------------------
James S. M. French
Director
March 12, 2004 By /s/ T. Michael Goodrich
- -------------- --------------------------------------
T. Michael Goodrich
Director
March 12, 2004 By /s/ Judy M. Merritt
- -------------- --------------------------------------
Judy M. Merritt
Director
March 12, 2004 By /s/ David W. Wilson
- -------------- --------------------------------------
David W. Wilson
Director
85