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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