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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, 2002
[] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___
COMMISSION IRS EMPLOYER
FILE STATE OF IDENTIFICATION
NUMBER REGISTRANT INCORPORATION NUMBER
---------- -------------------------- ------------------- ---------------
1-7810 ENERGEN CORPORATION 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. ( )
Aggregate market value of the voting stock held by non-affiliates of the
registrants as of June 30, 2002:
Energen Corporation $931,042,350
Indicate number of shares outstanding of each of the registrant's classes of
common stock as of March 5, 2003:
Energen Corporation 34,868,363 shares
Alabama Gas Corporation 1,972,052 shares
Alabama Gas Corporation meets the conditions set forth in General Instruction
I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced
disclosure format pursuant to General Instruction I(2).
DOCUMENTS INCORPORATED BY REFERENCE
Energen Corporation Proxy Statement to be filed on or about March 20,
2003 (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
the exposure to variability in cash flows from the
forecasted sale of oil, gas or natural gas liquids
production whereby the gains (losses) on the
derivative transaction are 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 statigraphic horizon
known to be productive.
EXPLORATORY WELL A well drilled to a previously untested geologic
structure to determine the presence of oil or gas.
FUTURES CONTRACT An exchange-traded legal contract to buy or sell a
standard quantity and quality of a commodity at a
specified future date and price. Such contracts offer
liquidity and minimal credit risk exposure but lack
the flexibility of swap contracts.
HEDGING The use of derivative commodity instruments such as
futures, swaps and collars to help reduce financial
exposure to commodity price volatility.
LIQUIFIED NATURAL GAS Natural gas that is liquified by 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 detectable by smell.
OPERATIONAL ENHANCEMENT Any action undertaken to improve production
efficiency of oil and gas wells and/or reduce well
costs.
OPERATOR The company responsible for exploration, development
and production activities for a specific project.
PAY-ADD An operation within a currently producing wellbore
that attempts to access and complete an additional
pay zone(s) while maintaining production from the
existing completed zone(s).
PAY ZONE The formation from which oil and gas is produced.
PROVED DEVELOPED RESERVES The portion of proved reserves which can be expected
to be recovered through existing wells with existing
equipment and operating methods.
PROVED RESERVES Estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering
data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED The portion of proved reserves which can be expected
RESERVES (PUD) to be recovered from new wells on undrilled proved
acreage or from existing wells where a relatively
major expenditure is required for completion.
PUT OPTION A contract that gives the purchaser the right, but
not the obligation, to sell the underlying commodity
at a certain price on or before an agreed date.
RECOMPLETION An operation within an existing wellbore whereby a
completion in one pay zone is abandoned in order to
attempt a completion in a different pay zone.
RESERVES-TO- Ratio expressing years of supply determined by
PRODUCTION RATIO dividing the remaining recoverable reserves at year
end by actual annual production volumes.
SECONDARY RECOVERY The process of injecting water, gas, etc., into 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
2002 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 Stock 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...........................28
Item 8. Financial Statements and Supplementary Data..........................................29
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................................73
PART III
Item 10. Directors and Executive Officers of the Registrants..................................74
Item 11. Executive Compensation...............................................................74
Item 12. Security Ownership of Certain Beneficial Owners and Management.......................74
Item 13. Certain Relationships and Related Transactions.......................................74
PART IV
Item 14. Controls and Procedures..............................................................75
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.....................75
Signatures .....................................................................................79
Certifications .....................................................................................81
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This Form 10-K is filed on behalf of Energen Corporation (Energen or the
Company) and Alabama Gas Corporation (Alagasco).
FORWARD-LOOKING STATEMENT AND RISK: Certain statements in this report express
expectations of future plans, objectives and performance of the Company and its
subsidiaries and constitute forward-looking statements made pursuant to the Safe
Harbor provision of the Private Securities Litigation Reform Act of 1995. Except
as otherwise disclosed, the Company's forward-looking statements do not reflect
the impact of possible or pending acquisitions, divestitures or restructurings.
The Company cannot guarantee the absence of errors in input data, calculations
and formulas used in its estimates, assumptions and forecasts. The Company
undertakes no obligation to correct or update any forward-looking statements
whether as a result of new information, future events or otherwise.
All statements based on future expectations rather than on historical facts are
forward-looking statements that are dependent on certain events, risks and
uncertainties that could cause actual results to differ materially from those
anticipated. Some of these include, but are not limited to, economic and
competitive conditions, inflation rates, legislative and regulatory changes,
financial market conditions, future business decisions, and other uncertainties,
all of which are difficult to predict.
There are numerous uncertainties inherent in estimating quantities of proved oil
and gas reserves and in projecting future rates of production and timing of
development expenditures. The total amount or timing of actual future production
may vary significantly from reserve and production estimates. In the event
Energen Resources Corporation is unable to fully invest its planned acquisition,
development and exploratory expenditures, future operating revenues, production,
and proved reserves could be negatively affected. The drilling of development
and exploratory wells can involve significant risks, including those related to
timing, success rates and cost overruns and these risks can be affected by lease
and rig availability, complex geology and other factors.
Although Energen Resources makes use of futures, swaps and fixed-price contracts
to mitigate risk, fluctuations in future oil and gas prices could materially
affect the Company's financial position and results of operation; furthermore,
such risk mitigation activities may cause the Company's financial position and
results of operations to be materially different from results that would have
been obtained had such risk mitigation activities not occurred. The
effectiveness of such risk-mitigation assumes that counterparties maintain
satisfactory credit quality.
PART I
ITEM 1. BUSINESS
GENERAL
Energen Corporation is a Birmingham-based diversified energy holding company
engaged primarily in 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.
The Company maintains a Web site with the address www.energen.com. The Company
does not include the information contained on its Web site as part of this
report nor is the information incorporated by reference into
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this report. The Company makes available free of charge through its Web site the
annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports
on Form 8-K, and any amendments to these reports. These reports are provided as
soon as reasonably practicable after such reports are electronically filed with
or furnished to the Securities and Exchange Commission.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The information required by this item is provided in Note 20, 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 production
and all oil and natural gas liquids production is sold to third
parties. Energen Resources also provides operating services in the
Black Warrior Basin in Alabama for its partners and third parties.
These services include overall project management and day-to-day
decision-making relative to project operations.
At the end of 2002, Energen Resources' inventory of proved oil and gas
reserves totaled 1,262.9 billion cubic feet equivalent (Bcfe).
Substantially all of the company's approximately 1.3 trillion cubic
feet equivalent of reserves are located in the San Juan Basin in New
Mexico, the Black Warrior Basin in Alabama, the Permian Basin in west
Texas, and the north Louisiana/east Texas region. Approximately 82
percent of Energen Resources' year-end reserves are proved developed
reserves. Energen Resources reserves are long-lived, with a year-end
reserves-to-production ratio of 16. Natural gas represents
approximately 64 percent of Energen Resources' proved reserves, with
oil representing approximately 24 percent and natural gas liquids
comprising the balance.
GROWTH STRATEGY: Energen has operated for more than seven years under a
strategy to grow its oil and gas operations. Since the end of fiscal
year 1995, Energen Resources has invested approximately $715 million in
property acquisitions, $435 million in related development, and $90
million in exploration and associated development. Energen Resources'
capital investment for oil and gas activities over the five-year period
ending December 31, 2007, is currently expected to approximate $835
million.
Energen Resources' approach to the oil and gas business calls for the
company to pursue onshore North American property acquisitions which
offer proved undeveloped (PUD) and/or behind-pipe reserves as well as
operational enhancement potential. Energen Resources prefers operated
natural gas properties with long-lived reserves and multiple pay-zone
opportunities; however, Energen Resources does not preclude possible
acquisitions of properties that otherwise meet its investment
requirements.
Following an acquisition, Energen Resources focuses on increasing
production and reserves through development of the properties' PUD and
behind-pipe reserve potential as well as engaging in other development
activities. These activities include development well drilling,
behind-pipe recompletions, pay-adds, workovers, secondary recovery and
operational enhancements. Energen Resources prefers to operate its
properties in order to better control the nature and pace of
development activities.
Energen Resources' development activities can result in the addition of
new proved reserves and can serve to reclassify proved undeveloped
reserves to proved developed reserves. Proved reserve disclosures are
provided annually, although changes to reserve classifications occur
throughout the year. Accordingly, additions of new reserves from
development activities can occur throughout the year and may result
from numerous factors including, but not limited to, regulatory
approvals for drilling unit downspacing which increase the number of
available drilling locations; changes in the economic or operating
environments which allow previously uneconomic locations to be added;
technological advances which make reserve locations available for
4
development; successful development of existing PUD locations which
reclassify adjacent probable locations to PUD locations; increased
knowledge of field geology and engineering parameters relative to oil
and gas reservoirs; and changes in management's intent to develop
certain opportunities.
Since the end of fiscal year 1999, the Company's development efforts
have added approximately 298 Bcfe of proved reserves from the drilling
of approximately 540 gross development wells and 408 well recompletions
and pay-adds. In 2002, Energen Resources' successful development wells
and other activities added approximately 162 Bcfe of proved reserves.
The company drilled 232 gross development wells, performed some 95 well
recompletions and pay-adds, and conducted other operational
enhancements. Energen Resources' production from continuing operations
totaled 77.4 Bcfe in 2002 and is estimated to total 85 Bcfe in 2003,
including 82.4 Bcfe of estimated production from proved reserves owned
at December 31, 2002.
Most of Energen Resources' coalbed methane production generated
nonconventional fuels tax credits through December 31, 2002. In 2002,
Energen Resources' nonconventional fuels tax credits totaled $14.2
million. Nonconventional fuels tax credits are no longer generated due
to tax law changes effective December 31, 2002. To mitigate the effects
on corporate earnings in 2003, Energen Resources has replaced a portion
of the tax credit benefit with long-term, revenue-generating property
acquisitions and their related development activities and has increased
the number of available drilling locations through unit downspacing in
the Black Warrior Basin.
RISK MANAGEMENT: Energen Resources attempts to lower the risk
associated with its oil and natural gas business. A key component of
the company's efforts to manage risk is its acquisition versus
exploration orientation and its preference for long-lived reserves. In
pursuing an acquisition, Energen Resources primarily uses in its
evaluation models the then-current oil and gas futures prices, the
prevailing swap curve and, for the longer-term, its own pricing
assumptions. After a purchase, Energen Resources may use futures, swaps
and/or fixed-price contracts to hedge commodity prices on flowing
production for up to 36 months to help protect targeted returns from
price volatility. On an on-going basis, Energen Resources may hedge up
to 80 percent of its annual production in any given year depending on
its pricing outlook.
The Company adopted Statement of Financial Accounting Standards (SFAS)
No. 133 (subsequently amended by SFAS Nos. 137 and 138), "Accounting
for Derivative Instruments and Hedging Activities," on October 1, 2000.
This statement requires all derivatives to be recognized on the balance
sheet and measured at fair value. If a derivative is designated as a
cash flow hedge, the Company is required to measure the effectiveness
of the hedge, or the degree that the gain (loss) for the hedging
instrument offsets the loss (gain) on the hedged item, at each
reporting period. The effective portion of the gain or loss on the
derivative instrument is recognized in other comprehensive income as a
component of equity and subsequently reclassified into earnings when
the forecasted transaction affects earnings. The ineffective portion of
a derivative's change in fair value is required to be recognized in
earnings immediately. Derivatives that do not qualify for hedge
treatment under SFAS No. 133 must be recorded at fair value with gains
or losses recognized in earnings in the period of change.
The Company periodically enters into derivative transactions that do
not qualify for cash flow hedge accounting but are considered by
management to represent valid economic hedges and are accounted for as
mark-to-market transactions. These economic hedges may include, but are
not limited to, basis hedges without a corresponding New York
Mercantile Exchange (NYMEX) hedge, put options and hedges on
non-operated or other properties for which all of the necessary
information to qualify for cash flow hedge accounting is either not
readily available or subject to change.
See the Forward-Looking Statement and Risk in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of
Operations, for further discussion with respect to price and other
risk.
ENVIRONMENTAL MATTERS: Energen Resources is subject to various
environmental regulations. Management believes that Energen Resources
is in compliance with currently applicable standards of the
environmental agencies to which it is subject and that potential
environmental liabilities are minimal. Also, to the extent that
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Energen Resources has operating agreements with various joint venture
partners, environmental costs would be shared proportionately.
OTHER: For a discussion of risks inherent in the Company's businesses,
see Item 7, Management's Discussion and Analysis of Financial Condition
and Results of Operations.
- - NATURAL GAS DISTRIBUTION
GENERAL: Alagasco 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 188 cities and communities in 28
counties. The aggregate population of the counties served by Alagasco
is estimated to be 2.3 million. Among the cities served by Alagasco are
Birmingham, the center of the largest metropolitan area in Alabama, and
Montgomery, the state capital. During 2002, Alagasco served an average
of 425,630 residential customers and 35,601 commercial, industrial and
transportation customers. The Alagasco distribution system includes
approximately 9,723 miles of main and more than 11,395 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 as extended, the APSC conducts quarterly reviews to
determine, based on Alagasco's projections and year-to-date
performance, whether Alagasco's return on average equity at the end of
the rate year will be within the allowed range. 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 performs this real-time
temperature adjustment calculation monthly, and the adjustments to
customers' bills are made in the same billing cycle in which the
weather variation occurs. Substantially all the customers to whom the
temperature adjustment applies are residential, small commercial and
small industrial. Alagasco's rate schedules for natural gas
distribution charges contain a Gas Supply Adjustment (GSA) rider that
permits the pass-through to customers of changes in the cost of gas
supply.
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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 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 and has firm
transportation contracts with two major interstate pipeline systems -
Southern Natural Gas Company (Southern) and Transcontinental Gas Pipe
Line Corporation (Transco). On Southern's system, Alagasco has 251,679
thousand cubic feet (Mcfd) of No-Notice Firm Transportation service
through October 31, 2008, and 134,332 Mcfd of Firm Transporation
service, of which 40,000 Mcfd expires April 30, 2005, 1,959 Mcfd
expires October 31, 2005 and the balance expires October 31, 2008. The
Transco Firm Transportation contract, which expires October 31, 2005,
provides for up to 100,000 Mcfd. As a result, Alagasco has a peak day
firm interstate pipeline transportation capacity of 486,011 Mcfd.
Alagasco has 12,464,074 Mcf of storage capacity on Southern's system,
with a maximum withdrawal rate of 251,679 Mcfd from storage and a
maximum injection rate of 95,878 Mcfd to storage. Alagasco also
operates two liquified natural gas (LNG) facilities used to meet peak
demand.
Alagasco purchases gas from various gas producers and marketers,
including affiliates of Southern, and from certain intrastate producers
and marketers. Alagasco has contracts in place to purchase up to
233,230 Mcfd of firm supply, of which 234,332 Mcfd is supported by firm
transportation on the Transco and Southern systems and approximately
21,450 Mcfd is purchased at the city gate under intrastate firm supply
contracts. These firm supply volumes along with Alagasco's maximum
withdrawal from storage of 251,679 Mcfd and LNG peak-shaving capacity
of 200,000 Mcfd, give Alagasco a peak day firm supply of 684,909 Mcfd.
Alagasco also utilizes the Southern pipeline systems to access spot
market gas in order to supplement its firm system supply and serve its
industrial and large commercial transportation customers. Deliveries of
sales and transportation gas totaled 97,840 million cubic feet in 2002.
COMPETITION AND 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
customers' gas load in the deregulated marketplace. Rate flexibility
remains critical as the utility faces competition for the large
customer load. To date, the utility has been effective in utilizing its
flexible rate strategies to minimize bypass and price-based switching
to alternate fuels and alternate sources of gas.
In 1994 Alagasco implemented the P Rate in response to the competitive
challenge of interstate pipeline capacity release. Under this tariff
provision, Alagasco releases much of its excess pipeline capacity and
repurchases it as agent for its transportation customers 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 2002, approximately 300 of Alagasco's transportation
customers utilized the P Rate, and the resulting reduction in core
market gas costs totaled approximately $9.1 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
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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 2002 substantially all of Alagasco's large
commercial and industrial customer deliveries were the transportation
of customer-owned gas. In addition, Alagasco served as gas purchasing
agent for approximately 99 percent of its transportation customers.
Alagasco also uses long-term special contracts as a vehicle for
retaining large customer load. At the end of 2002, 49 of the utility's
largest commercial and industrial transportation customers were under
special contracts of varying lengths.
Natural gas service available to Alagasco customers falls into two
broad categories: interruptible and firm. Interruptible service
contractually is subject to interruption by Alagasco for various
reasons; the most common occurrence is curtailment of industrial
customers during periods of peak core market heating demand.
Interruptible service typically is provided to large commercial and
industrial transportation customers who can reduce their gas
consumption by adjusting production schedules or by switching to
alternate fuels for the duration of the service interruption. More
expensive firm service, on the other hand, generally is not subject to
interruption and is provided to residential and small commercial and
industrial customers; these core market customers depend on natural gas
primarily for space heating.
GROWTH: Customer growth presents a major challenge for Alagasco, given
its mature, slow-growth service area. In 2002, Alagasco's average
number of customers declined slightly due to the previous year's high
gas costs and industrial load loss resulting from an economic slowdown.
The utility penetrated 86 percent of the new single-family housing
market in its service area and 18 percent of the new multi-family
housing market. For 2003, Alagasco will concentrate on maintaining its
current penetration levels in the residential new construction market
while increasing its focus on generating additional revenue in the
small and large commercial and industrial market segments.
A vehicle for supplementing Alagasco's normal growth 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.
OTHER: 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 1,533 employees; Alagasco employs 1,259; Energen Resources
employs 261; and Energen's other subsidiaries employ 13. The Company believes
that its relations with employees are good.
8
ITEM 2. PROPERTIES
The corporate headquarters of Energen, Alagasco and 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,
reserves and development is summarized in the table below and included in Note
19, Oil and Gas Operations (unaudited), in the Notes to Financial Statements
which is included in this Form 10-K.
YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2002
----------------- -----------------
Production Volumes Reserves
(MMcfe) (MMcfe)
----------------- -----------------
San Juan Basin 27,133 548,744
Permian Basin 23,878 357,455
Black Warrior Basin 13,494 257,662
North Louisiana/East Texas 11,376 82,086
Other 2,092 16,981
------ ---------
Total 77,973 1,262,928
====== =========
The properties of Alagasco consist primarily of its gas distribution system,
which includes more than 9,723 miles of main, more than 11,395 miles of service
lines, odorization and regulation facilities, and customer meters. Alagasco also
has two LNG facilities, seven division offices, four payment centers, five
district offices, nine service centers, and other related property and
equipment, some of which are leased by Alagasco. For a further description of
Alagasco's properties, see 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 2002.
9
EXECUTIVE OFFICERS OF THE REGISTRANTS
ENERGEN CORPORATION
Name Age Position (1)
- ---- --- ------------
Wm. Michael Warren, Jr. 55 Chairman of the Board
President and Chief Executive Officer (2)
Geoffrey C. Ketcham 52 Executive Vice President, Chief Financial Officer
and Treasurer (3)
James T. McManus 44 President and Chief Operating Officer of Energen
Resources (4)
Dudley C. Reynolds 50 President and Chief Operating Officer of Alagasco
(5)
Grace B. Carr 47 Vice President and Controller (6)
J. David Woodruff, Jr. 46 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 as 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 as 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.
10
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE
Quarter ended (in dollars) HIGH LOW CLOSE DIVIDENDS PAID
- -------------------------- ---- --- ----- --------------
December 31, 1999 21.25 15.75 18.06 .165
March 31, 2000 18.94 14.69 15.94 .165
June 30, 2000 23.69 16.00 21.81 .165
September 30, 2000 30.38 21.00 29.75 .170
------- ------ ------ -----
December 31, 2000 33.56 26.06 32.19 .170
March 31, 2001 35.30 27.50 35.30 .170
June 30, 2001 40.25 26.75 27.60 .170
September 30, 2001 28.21 21.50 22.50 .175
------- ------ ------ -----
December 31, 2001 25.20 21.50 24.65 .175
------- ------ ------ -----
March 31, 2002 26.49 21.69 26.45 .175
June 30, 2002 29.25 24.70 27.50 .175
September 30, 2002 27.53 21.65 25.31 .180
December 31, 2002 29.99 22.50 29.10 .180
------- ------ ------ -----
Energen's common stock is listed on the New York Stock Exchange under the symbol
EGN. On February 14, 2003, there were approximately 7,930 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 Remaining
Number of Securities to Weighted Available for Future Issuance
be Issued Upon Exercise Average Under Equity Compensation Plans
Plan Category of Outstanding Options Exercise Price
------------- ---------------------- -------------- -------------------------------
Equity compensation plans
approved by security holders 621,007 $20.38 2,326,897
Equity compensation plans not
approved by security holders -- -- --
------- ------ ---------
Total 621,007 $20.38 2,326,897
======= ====== =========
11
ITEM 6. SELECTED FINANCIAL DATA
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 Ended Year Ended Year Ended Year Ended Year Ended Year Ended
(dollars in thousands, DECEMBER 31, December 31, September 30, September 30, September 30, September 30, September 30,
except per share amounts) 2002 2001* 2001 2000 1999 1998 1997
------------ ------------- ------------ ------------- ------------- ------------- -------------
INCOME STATEMENT
Operating revenues $ 677,175 $ 146,164 $ 777,374 $ 551,409 $ 492,942 $498,398 $446,684
Income from continuing
operations before
cumulative effect of
change in accounting
principle $ 70,586 $ 3,579 $ 66,087 $ 52,535 $ 41,453 $ 35,828 $ 28,736
Net income $ 68,639 $ 3,658 $ 67,896 $ 53,018 $ 41,410 $ 36,249 $ 28,997
Diluted earnings
per average
common share from
continuing operations
before cumulative
effect of change in
accounting principle $ 2.09 $ 0.12 $2.13 $ 1.73 $ 1.38 $ 1.22 $ 1.13
Diluted earnings
per average
common share $ 2.03 $ 0.12 $2.18 $ 1.75 $ 1.38 $ 1.23 $ 1.14
---------- ----------- ---------- ---------- ---------- -------- --------
BALANCE SHEET
Capitalization at
year-end:
Common shareholders'
equity $ 582,810 $ 474,205 $ 480,767 $ 400,860 $ 361,504 $329,249 $301,143
Long-term debt 512,954 544,133 544,110 353,932 371,824 372,782 279,602
---------- ----------- ---------- ---------- ---------- -------- --------
Total capitalization $1,095,764 $1,018,338 $1,024,877 $ 754,792 $ 733,328 $702,031 $580,745
---------- ----------- ---------- ---------- ---------- -------- --------
Total assets $1,530,891 $1,240,356 $1,223,879 $1,203,041 $1,184,895 $993,455 $919,797
---------- ----------- ---------- ---------- ---------- -------- --------
Property, plant and
equipment, net $1,256,803 $1,005,679 $ 998,334 $ 907,829 $ 861,107 $756,344 $667,003
========== ========== ========== ========== ========== ======== ========
COMMON STOCK DATA
Annual dividend rate at
period-end $ 0.72 $ 0.70 $ 0.70 $ 0.68 $ 0.66 $ 0.64 $ 0.62
Cash dividends paid per
common share $ 0.71 $ 0.175 $ 0.685 $ 0.665 $ 0.645 $ 0.625 $ 0.605
Book value per common share $ 16.77 $ 15.18 $ 15.45 $ 13.21 $ 12.09 $ 11.23 $ 10.46
Market-to-book ratio at
period-end (%) 174 162 145 225 167 169 170
Yield at period-end (%) 2.5 2.8 3.1 2.3 3.3 3.4 3.5
Return on average common
equity excluding other
comprehensive
income(%)** 12.4 12.6 15.3 13.7 11.7 11.1 11.9
Return on average common
equity (%) 12.4 13.0 15.8 13.7 11.7 11.1 11.9
Price-to-earnings
(diluted) ratio at
period-end 14.3 -- 10.3 17.0 14.7 15.4 15.6
Shares outstanding at
period-end (000) 34,745 31,249 31,125 30,351 29,904 29,327 28,796
Price Range:
High $ 29.99 $ 25.20 $ 40.25 $ 30.38 $ 20.38 $ 22.50 $ 18.88
Low $ 21.65 $ 21.50 $ 21.50 $ 14.69 $ 13.13 $ 15.13 $ 11.88
Close $ 29.10 $ 24.65 $ 22.50 $ 29.75 $ 20.25 $ 19.00 $ 17.78
Note: All information has been adjusted to reflect the 2-for-1 stock split
effective March 2, 1998
*On December 5, 2001, the Board of Directors of the Company approved a change in
the Company's fiscal year end from September 30 to December 31, effective
January 1, 2002. A transition report was filed on Form 10-Q for the period
October 1, 2001 to December 31, 2001.
**The comparable generally accepted accounting principle measure is return on
average common equity.
12
SELECTED BUSINESS SEGMENT DATA
Energen Corporation
Three Months
YEAR ENDED Ended Year Ended
DECEMBER 31, December 31, September 30,
(dollars in thousands) 2002 2001* 2001
------------ ------------ -------------
OIL AND GAS OPERATIONS
Operating revenues from
continuing operations
Natural gas $150,899 $35,324 $141,505
Oil 75,426 12,375 48,016
Natural gas liquids 22,849 4,533 26,011
Other 3,570 (2,746) 7,980
-------- ------- --------
Total $252,744 $49,486 $223,512
-------- ------- --------
Production volumes from continuing
operations
Natural gas (MMcf) 47,776 11,886 45,847
Oil (MBbl) 3,139 512 2,019
Natural gas liquids (MBbl) 1,792 450 1,477
-------- ------- --------
Production volumes from continuing
operations (MMcfe) 77,360 17,656 66,823
-------- ------- --------
Total production volumes (MMcfe) 77,973 18,022 68,478
-------- ------- --------
Proved reserves
Natural gas (MMcf) 803,748 714,395 627,051
Oil (MBbl) 49,833 19,128 20,878
Natural gas liquids (MBbl) 26,697 25,944 24,931
-------- ------- --------
Other data from continuing operations
Depreciation and amortization $ 71,405 $16,351 $ 53,846
Capital expenditures $305,476 $25,052 $136,886
Operating income $ 78,416 $ 3,243 $ 72,425
-------- ------- --------
NATURAL GAS DISTRIBUTION
Operating revenues
Residential $277,088 $63,724 $367,109
Commercial and industrial-small 104,247 22,445 147,636
Transportation 38,395 9,765 33,972
Other 4,701 744 5,145
-------- ------- --------
Total $424,431 $96,678 $553,862
-------- ------- --------
Gas delivery volumes (MMcf)
Residential 26,358 5,128 31,064
Commercial and industrial-small 11,838 2,193 14,054
Transportation 59,644 12,973 53,989
-------- ------- --------
Total 97,840 20,294 99,107
-------- ------- --------
Average number of customers
Residential 425,630 422,461 428,663
Commercial, industrial and
transportation 35,601 35,161 35,882
-------- ------- --------
Total 461,231 457,622 464,545
-------- ------- --------
Other data
Depreciation and amortization $ 33,682 $ 8,151 $ 30,933
Capital expenditures $ 65,815 $12,873 $ 56,090
Operating income $ 59,370 $ 8,034 $ 50,288
-------- ------- --------
Year Ended Year Ended Year Ended Year Ended
September 30, September 30, September 30, September 30,
(dollars in thousands) 2000 1999 1998 1997
------------- ------------- ------------- -------------
OIL AND GAS OPERATIONS
Operating revenues from
continuing operations
Natural gas $118,271 $116,555 $93,958 $59,474
Oil 39,220 35,207 20,472 13,199
Natural gas liquids 22,662 7,207 6,977 5,762
Other 5,095 8,419 7,051 5,265
-------- -------- -------- --------
Total $185,248 $167,388 $128,458 $83,700
-------- -------- -------- --------
Production volumes from continuing
operations
Natural gas (MMcf) 47,441 52,754 42,432 28,995
Oil (MBbl) 2,140 2,937 1,378 734
Natural gas liquids (MBbl) 1,411 757 817 502
-------- -------- -------- --------
Production volumes from continuing
operations (MMcfe) 68,756 74,919 55,599 36,412
-------- -------- -------- --------
Total production volumes (MMcfe) 70,482 77,159 57,353 36,980
-------- -------- -------- --------
Proved reserves
Natural gas (MMcf) 777,456 740,001 542,039 544,283
Oil (MBbl) 24,518 24,719 19,845 9,128
Natural gas liquids (MBbl) 26,007 21,937 17,292 12,378
-------- -------- -------- --------
Other data from continuing operations
Depreciation and amortization $ 56,226 $ 59,322 $ 54,192 $ 35,729
Capital expenditures $ 67,090 $198,577 $120,991 $239,718
Operating income $ 47,568 $ 31,089 $ 20,299 $ 14,295
-------- -------- -------- --------
NATURAL GAS DISTRIBUTION
Operating revenues
Residential $233,839 $209,263 $241,964 $237,022
Commercial and industrial-small 88,521 77,254 89,361 87,477
Transportation 35,312 34,541 35,246 33,080
Other 8,489 4,496 3,369 5,405
-------- -------- -------- --------
Total $366,161 $325,554 $369,940 $362,984
-------- -------- -------- --------
Gas delivery volumes (MMcf)
Residential 26,069 24,751 31,079 28,357
Commercial and industrial-small 12,092 11,662 13,705 12,554
Transportation 70,534 66,356 70,563 65,622
-------- -------- -------- --------
Total 108,695 102,769 115,347 106,533
-------- -------- -------- --------
Average number of customers
Residential 429,368 425,937 423,602 422,878
Commercial, industrial and
transportation 35,526 35,111 34,782 34,485
-------- -------- -------- --------
Total 464,894 461,048 458,384 457,363
-------- -------- -------- --------
Other data
Depreciation and amortization $28,708 $26,730 $25,153 $23,486
Capital expenditures $67,073 $46,029 $54,168 $43,277
Operating income $49,063 $46,565 $41,663 $38,792
-------- -------- -------- --------
13
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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 judgements 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.
Estimates of physical quantities of oil and gas reserves are determined by
Company engineers and, in some cases, by third-party experts. Proved oil and gas
reserves are the estimated quantities of crude oil, natural gas and natural gas
liquids that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Accordingly, these estimates do not include
probable or possible reserves. Estimated oil and gas reserves are based on
currently available reservoir data and are subject to future revision. The
Company's production of undeveloped reserves require the installation or
completion of related infrastructure facilities such as pipelines and the
drilling of development wells.
Changes in oil and gas prices, operating costs and expected performance from the
properties will 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 expenses or due to an immediate writedown of the
property's book value if an impairment is warranted. The table below reflects
the estimated effect on depreciation and depletion expense for 2003 of changes
in oil and gas reserve quantities from the reported amounts at December 31,
2002.
Percentage Change in Oil & Gas Reserves
From Reported Reserves as of December 31, 2002
(dollars in thousands) +10% +5% -5% -10%
------- ------- ------- -------
Estimated change in depreciation expense for
the year ended December 31, 2003, net of tax $(4,300) $(2,100) $ 2,400 $ 5,200
------- ------- ------- -------
ASSET IMPAIRMENTS: Oil and gas developed and undeveloped properties periodically
are assessed for possible impairment, generally on a field-by-field basis, using
the estimated undiscounted future cash flows of each field. Impairment losses
are recognized when the estimated undiscounted future cash flows are less than
the current net book values of the properties in a field. The Company monitors
its oil and gas properties as well as the market and business environments in
which it operates and makes assessments about events that could result in
potential impairment issues. Such potential events may include, but are not
limited to, substantial commodity price declines, unanticipated increased
operating costs, and lower-than-expected production performance from the
properties. If a material event occurs, Energen Resources makes an estimate of
undiscounted future cash flows to determine whether the asset is impaired. If
the asset is impaired, the Company will record an impairment loss for the
difference between the net book value of the properties and the fair value of
the properties. The fair value of the properties typically is estimated using
discounted cash flow.
Cash flow and fair value estimates require Energen Resources to make projections
and assumptions for pricing, demand, competition, operating costs, legal and
regulatory issues, discount rates and other factors for many years into the
future. These variables can, and often do, differ from the estimate and can have
a positive or negative
14
impact on the Company's need for impairment or of the amount of impairment. In
addition, further changes in the economic and business environment can impact
the Company's original and ongoing assessments of potential impairment.
NATURAL GAS DISTRIBUTION
REGULATED OPERATIONS: Alagasco applies SFAS No. 71, "Accounting for the Effects
of Certain Types of Regulation," to its regulated operations. This standard
requires a cost to be capitalized as a regulatory asset that otherwise would be
charged to expense if it is probable that the cost is recoverable in the future
through regulated rates. Likewise, if current recovery is provided for a cost
that will be incurred in the future, SFAS No. 71 requires the cost to be
recognized as a regulatory liability. The Company anticipates SFAS No. 71 will
continue as the applicable accounting standard for its regulated operations.
Alagasco's rate setting methodology, Rate Stabilization and Equalization, has
been in effect since 1983.
CONSOLIDATED
EMPLOYEE BENEFIT PLANS: Determining the Company's obligations to employees under
its defined benefit pension plan requires the use of estimates. The calculation
of the liability related to the Company's defined benefit pension plan requires
assumptions regarding the appropriate weighted average discount rate, estimated
rate of increase in the compensation level of its employee base and the expected
long-term rate of return on the plans' assets. The selection and use of such
assumptions affects the amount of expense recorded in the Company's financial
statements related to its defined benefit pension plan. The discount rate for
pension cost purposes is the rate at which pension obligations could be
effectively settled. At December 31, 2002 the discount rate used for actuarial
purposes was 6.75 percent. A hypothetical basis point change in the discount
rate would impact total pension expense by approximately $560,000. The assumed
rate of return on assets is the weighted average of expected long-term asset
assumptions. At December 31, 2002, the return on assets used for actuarial
purposes was 9 percent. A hypothetical 25 basis point change in the return on
assets would impact total pension expense by approximately $245,000.
CHANGE IN YEAR END
On December 5, 2001, the Board of Directors of the Company approved a change in
the Company's fiscal year end from September 30 to December 31, effective
January 1, 2002. A transition report was filed on Form 10-Q for the period
October 1, 2001 to December 31, 2001. Alagasco will continue on a September 30
fiscal year for rate-setting purposes (rate year) and will report on a calendar
year for the Securities and Exchange Commission and all other financial
accounting reporting purposes.
RESULTS OF OPERATIONS
CONSOLIDATED NET INCOME
Energen Corporation's net income for the year ended December 31, 2002 totaled
$68.6 million, or $2.03 per diluted share compared to fiscal year ended
September 30, 2001 net income of $67.9 million, or $2.18 per diluted share. This
7 percent decrease in earnings per diluted share (EPS) reflects an increase in
the number of shares outstanding related to the acquisition of oil and gas
properties in the Permian Basin in April 2002. Energen Resources Corporation,
Energen's oil and gas subsidiary, had a slight decrease in earnings for the 12
months ended December 31, 2002, as compared with the 12 months ended September
30, 2001. Alabama Gas Corporation (Alagasco), Energen's utility subsidiary,
generated a 6 percent increase in net income in the same period comparisons. For
the 12 months ended September 30, 2000, Energen reported earnings of $53
million, or $1.75 per diluted share.
2002 VS 2001: For the year ended December 31, 2002, Energen Resources' net
income totaled $41.2 million as compared with $42.6 million for the 12 months
ended September 30, 2001. Net income in the current year included a non-cash
benefit of $5.7 million after-tax ($0.17 per diluted share) associated with its
previous hedge position with Enron North America Corp. (Enron) and a one-time
charge of $2.2 million after-tax ($0.07 per diluted share), reflecting the
cumulative effect on prior years of the adoption of SFAS No. 143, "Accounting
for Asset Retirement Obligations." Energen Resources' income from continuing
operations in 2002 totaled $43.2 million as compared with $40.8 million in
fiscal 2001, primarily due to a 15.8 percent increase in production volumes
related to an acquisition of oil properties in the Permian Basin in April 2002.
The primary negative influences on income from
15
operations were increased lease operating expense and increased depreciation,
depletion and amortization (DD&A) expense.
Alagasco's earnings increased to $27.6 million in 2002 from $26 million in
fiscal year 2001 as a result of the utility having increased earnings on a
higher level of equity. Alagasco achieved a return on average equity (ROE) of
12.3 percent in both 2002 and 2001.
2001 VS 2000: Energen Resources' net income in fiscal 2001 rose 55.2 percent to
$42.6 million. Energen Resources' income from continuing operations in fiscal
2001 totaled $40.8 million as compared with $26.9 million in fiscal 2000,
primarily due to a 23.3 percent increase in realized sales prices for natural
gas, oil and natural gas liquids production. The significantly higher realized
commodity prices more than compensated for the negative impact of increased
lease operating expense and a 1.9 Bcfe production decrease. Earnings in fiscal
year 2000 were negatively affected by a $2.2 million ($0.07 per diluted share)
after-tax writedown under SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of," for certain oil
and gas properties resulting from a downward reserve revision.
Alagasco's earnings declined 1.2 percent from $26.3 million in fiscal 2000 to
$26 million in fiscal year 2001. This slight decrease in income was primarily a
result of increased bad debt expense from significantly colder weather and
higher natural gas prices during the fiscal 2001 winter as well as industrial
load loss resulting from an economic slowdown. Alagasco achieved a return on
average equity (ROE) of 12.3 percent in 2001 as compared to 13.4 percent in
2000.
THREE MONTHS ENDED DECEMBER 31, 2001 VS THREE MONTHS ENDED DECEMBER 31, 2000:
Energen's net income totaled $3.7 million ($0.12 per diluted share) for the
three months ended December 31, 2001, compared to net income of $13.7 million
($0.44 per diluted share) recorded in the same period of 2000. Energen Resources
realized net income from continuing operations of $1.1 million in the December
31, 2001 transition quarter as compared with $9.3 million in the same quarter in
the previous year largely due to a one-time non-cash write-off of $5.5 million
after-tax ($0.17 per diluted share) associated with its hedge position with
Enron. Also negatively impacting net income in the transition quarter were
increased DD&A expense, a $1.7 million writedown on property held for sale and
lower natural gas liquids prices. Energen's natural gas utility, Alagasco,
reported net income of $2.7 million in the transition quarter as compared to $4
million in the same period in the previous year primarily due to increased bad
debt expense as well as a decline in cycle and industrial gas usage.
OPERATING INCOME
Consolidated operating income in 2002, 2001 and 2000 totaled $136 million, $121
million and $95 million, respectively. This significant growth in operating
income was influenced by strong financial performance from Energen Resources
under Energen's diversified growth strategy, implemented in fiscal 1996.
Alagasco also contributed to this growth in operating income consistent with an
increase in the level of equity upon which it has been able to earn a return.
OIL AND GAS OPERATIONS: Revenues from oil and gas operations rose significantly
in the current year largely as a result of increased production volumes related
to the acquisition of oil properties in the Permian Basin. During 2002,
production from continuing operations increased 15.8 percent to 77.4 Bcfe.
Natural gas production increased 4.2 percent to 47.8 Bcf and oil volumes rose
55.5 percent to 3,139 MBbl. Production of natural gas liquids increased 21.3
percent to 1,792 MBbl. Including the non-cash benefit from the former Enron
hedges, realized gas prices rose 2.3 percent to $3.16 per Mcf, while realized
oil prices increased 1.1 percent to $24.03 per barrel. Natural gas liquids
prices fell 27.6 percent to an average price of $12.75 per barrel.
In fiscal 2001, revenues from oil and gas continuing operations increased
largely as a result of significantly higher commodity prices as compared to the
previous fiscal year. Realized gas prices rose 24.1 percent to $3.09 per Mcf,
while realized oil prices increased 29.7 percent to $23.78 per barrel. Natural
gas liquids prices increased 9.7 percent to an average price of $17.61 per
barrel. During 2001, production from continuing operations declined slightly to
66.8 Bcfe as natural gas production decreased 3.4 percent to 45.8 Bcf and oil
volumes declined 5.7 percent to 2,019 MBbl. Production of natural gas liquids
increased 4.7 percent to 1,477 MBbl. This 1.9 Bcfe
16
decrease in production largely was due to normal production declines in Energen
Resources' coalbed methane and south Louisiana properties. Drilling in the San
Juan and Permian basins and in the north Louisiana/east Texas area served to
replace aggregate production in these areas.
Coalbed methane operating fees are calculated as a percentage of net proceeds on
certain properties, as defined by the related operating agreements, and vary
with changes in natural gas prices, production volumes and operating expenses.
Revenues from operating fees were $4.8 million, $7.6 million and $4.3 million in
2002, 2001 and 2000, respectively.
DECEMBER 31, September 30, September 30,
Years ended (in thousands, except sales price data) 2002 2001 2000
------------ ------------- -------------
Revenues from continuing operations
Natural gas production $ 150,899 $ 141,505 $ 118,271
Oil production 75,426 48,016 39,220
Natural gas liquids production 22,849 26,011 22,662
Operating fees 4,847 7,618 4,262
Other (1,277) 362 833
-------- -------- --------
Total revenues from continuing operations $ 252,744 $ 223,512 $ 185,248
-------- -------- --------
Production volumes from continuing operations
Natural gas (MMcf) 47,776 45,847 47,441
Oil (MBbl) 3,139 2,019 2,140
Natural gas liquids (MBbl) 1,792 1,477 1,411
-------- -------- --------
Average sales price including effects of hedging
Natural gas (per Mcf) $ 3.16 $ 3.09 $ 2.49
Oil (per barrel) $ 24.03 $ 23.78 $ 18.33
Natural gas liquids (per barrel) $ 12.75 $ 17.61 $ 16.06
-------- -------- --------
Average sales price excluding effects of hedging
Natural gas (per Mcf) $ 2.96 $ 4.86 $ 3.06
Oil (per barrel) $ 24.75 $ 27.46 $ 26.45
Natural gas liquids (per barrel) $ 12.75 $ 17.61 $ 16.06
-------- -------- --------
Energen Resources may, in the ordinary course of business, be involved in the
sale of developed or undeveloped properties. With respect to developed
properties, sales may occur as a result of, but not limited to, disposing of
non-strategic or marginal assets and accepting offers where the buyer gives
greater value to a property than does Energen Resources. The Company is required
to reflect gains and losses on the dispositions of these assets, the writedown
of certain properties held-for-sale, and income or loss from the operations of
the associated held-for-sale properties as discontinued operations under the
provisions of SFAS No. 144, which was adopted as of January 1, 2002. Energen
Resources recorded in 2002 a pre-tax gain of $0.9 million in total income from
discontinued operations from the sale of properties and adjustments to the fair
value of properties being held-for-sale. In 2001, prior to the adoption of SFAS
No. 144, Energen Resources recorded in operating revenues a net pre-tax gain
from the sale of properties and adjustments to the fair value of properties held
for sale of $0.8 million. Pre-tax gains from the sale of properties of $1.1
million were recorded in operating revenues in 2000.
Operations and maintenance (O&M) expense increased $10.3 million and $9.9
million in 2002 and 2001, respectively. Lease operating expense in 2002 rose
$7.6 million primarily due to the acquisition of oil and gas properties. In
2001, lease operating expense increased by $9.2 million largely due to
significantly higher operational costs driven by market conditions resulting
from increased commodity costs. In the current year, administrative expense
increased $3.5 million primarily due to labor related costs and additional cost
related to the property acquisition. Administrative expense increased $1.4
million in 2001. Exploration expense decreased $0.6 million in 2002 and $0.7
million in 2001, primarily due to reduced exploratory efforts.
DD&A expense increased $17.6 million in 2002 largely due to increased production
volumes and increased DD&A rates. In 2001, DD&A expense decreased $2.4 million
primarily due to lower production volumes and additional pre-tax DD&A expense of
$3.5 million recorded in 2000 to adjust the carrying amount of certain
properties to their
17
fair value based on expected future discounted cash flows (see Note 12). The
average depletion rate was $0.90 per Mcfe in 2002 as compared to $0.79 per Mcfe
in the prior year.
Energen Resources' expense for taxes other than income primarily reflected
production-related taxes. Energen Resources recorded severance taxes for 2002 of
$18.9 million. Severance taxes in 2001 were $23.9 million as a result of
increased commodity prices. In 2000, severance taxes were $17.3 million.
OIL AND GAS OPERATIONS - TRANSITION PERIOD: Revenues from oil and gas continuing
operations declined 9.8 percent to $49.5 million for the three months ended
December 31, 2001, largely as a result of lower natural gas liquids prices. In
the transition quarter, realized gas prices increased 8.4 percent to $2.97 per
Mcf, while realized oil prices rose 7.8 percent to $24.19 per barrel. Natural
gas liquids prices decreased 51.4 percent to an average price of $10.07 per
barrel.
Natural gas production in the transition quarter increased slightly to 11.9 Bcf,
while oil volumes decreased slightly to 512 MBbl. Natural gas liquids production
increased 13.9 percent to 450 MBbl. Natural gas comprised nearly 70 percent of
Energen Resources' production in the transition quarter.
DECEMBER 31, December 31,
Three months ended (in thousands, except sales price data) 2001 2000
------------ ------------
Revenues from continuing operations
Natural gas production $ 35,324 $32,316
Oil production 12,375 11,586
Natural gas liquids production 4,533 8,180
Operating fees 913 2,225
Other (3,659) 555
-------- -------
Total revenues from continuing operations $ 49,486 $54,862
-------- -------
Production volumes from continuing operations
Natural gas (MMcf) 11,886 11,796
Oil (MBbl) 512 516
Natural gas liquids (MBbl) 450 395
-------- -------
Average sales price including effects of hedging
Natural gas (per Mcf) $ 2.97 $ 2.74
Oil (per barrel) $ 24.19 $ 22.45
Natural gas liquids (per barrel) $ 10.07 $ 20.70
-------- -------
Average sales price excluding effects of hedging
Natural gas (per Mcf) $ 2.35 $ 5.15
Oil (per barrel) $ 19.79 $ 30.65
Natural gas liquids (per barrel) $ 10.07 $ 20.70
-------- -------
Prior to the adoption of SFAS No. 144, Energen Resources recorded in operating
revenues a pre-tax loss of $3.4 million for the current transition quarter from
the sale of properties and adjustments to the fair value of properties
held-for-sale as compared to a pre-tax gain of $0.8 million in the prior year
quarter on the sale of various properties.
O&M expense increased $8.6 million for the transition quarter ended December 31,
2001, largely due to the one-time non-cash writedown of $8.7 million pre-tax
associated with Energen Resources' hedge position with Enron. Lease operating
expenses increased by $0.4 million for the transition quarter while exploration
expense remained relatively stable.
Energen Resources' DD&A expense for the period rose $4.5 million primarily
driven by the impact of market declines in commodity prices. The average
depletion rate for the transition quarter was $0.91 as compared to $0.67 for the
same period in the previous year.
18
Energen Resources' expense for taxes other than income taxes primarily reflected
production-related taxes that were $3.3 million lower in the transition quarter
primarily as a result of the significantly decreased commodity market prices.
NATURAL GAS DISTRIBUTION: As discussed more fully in Note 2, Alagasco is subject
to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002,
the APSC issued an order to extend the Company's rate-setting mechanism. Under
the terms of that extension, RSE will continue after January 1, 2008, unless,
after notice to the Company and a hearing, the Commission votes to either modify
or discontinue its operation.
Alagasco generates revenues through the sale and transportation of natural gas.
The transportation rate does not contain an amount representing the cost of gas,
and Alagasco's rate structure allows similar margins on transportation and sales
gas. Weather can cause variations in space heating revenues, but operating
margins essentially remain unaffected due to a real-time temperature adjustment
mechanism that allows Alagasco to adjust customer bills monthly to reflect
changes in usage due to departures from normal temperatures. The temperature
adjustment applies to residential, small commercial and small industrial
customers.
Alagasco's natural gas and transportation sales revenues totaled $424.4 million,
$553.9 million and $366.2 million in 2002, 2001 and 2000, respectively. Lower
commodity gas costs and weather that was 13.1 percent warmer than in the prior
year contributed to the decrease in sales revenue in the current year. Sales
revenue in fiscal 2001 rose due to significantly higher commodity gas costs as
well as weather that was 29.9 percent colder than in fiscal year 2000.
In the current year, residential sales volumes decreased 15.1 percent primarily
due to the impact of warmer weather on throughput. Small commercial and
industrial volumes, also sensitive to weather, decreased 15.8 percent.
Transportation volumes rose 10.5 percent, due to the previous period's
significantly higher natural gas prices and a general economic weakness. During
2001, significantly colder weather in Alagasco's service territory caused a 19.2
percent increase in residential sales volumes and a 16.2 percent increase in
small commercial and industrial sales volumes. Transportation volumes decreased
23.5 percent, primarily due to the prior-year closing of a steel manufacturing
plant and reduced consumption resulting from an economic downturn during the
year.
In 2002, significantly lower commodity gas costs along with decreased purchased
volumes due to warmer weather resulted in a 41.9 percent decrease in cost of
gas. Higher commodity cost of gas, including record high prices in fiscal year
2001, along with increased purchased volumes resulting from colder weather
generated a 111.5 percent increase in cost of gas for fiscal year 2001.
O&M expense at the utility increased 3.1 percent in 2002 primarily due to higher
insurance and labor-related costs partially offset by reduced bad debt expense
and marketing costs. In fiscal 2001, O&M expense increased 1.5 percent primarily
as a result of increased bad debt expense and insurance costs largely offset by
reduced marketing and labor-related costs. The increase in O&M expense per
customer was above the inflation-based Cost Control Measurement (CCM)
established by the APSC as part of the utility's rate-setting mechanism, for the
rate year ended September 30, 2002; as a result, three quarters of the
difference, or $0.3 million pre-tax, was returned to the customers through RSE
(see Note 2). In 2001 and 2000, the increase in O&M expense on a per-customer
basis fell within the CCM.
Consistent with growth in the utility's depreciable base, depreciation expense
rose 8.9 percent in 2002 and 7.8 percent in 2001. Alagasco's expense for taxes
other than income primarily reflects various state and local business taxes as
well as payroll-related taxes. State and local business taxes generally are
based on gross receipts and fluctuate accordingly.
19
DECEMBER 31, September 30, September 30,
Years ended (in thousands) 2002 2001 2000
------------ ------------- -------------
Natural gas transportation and sales revenues $ 424,431 $ 553,862 $ 366,161
Cost of natural gas (191,479) (329,572) (155,841)
Revenue taxes (21,591) (28,766) (19,749)
--------- --------- ---------
Natural gas transportation and sales margin $ 211,361 $ 195,524 $ 190,571
--------- --------- ---------
Natural gas sales volumes (MMcf)
Residential 26,358 31,064 26,069
Commercial and industrial-small 11,838 14,054 12,092
--------- --------- ---------
Total natural gas sales volumes 38,196 45,118 38,161
Natural gas transportation volumes (MMcf) 59,644 53,989 70,534
--------- --------- ---------
Total deliveries (MMcf) 97,840 99,107 108,695
--------- --------- ---------
NATURAL GAS DISTRIBUTION - TRANSITION PERIOD: Natural gas distribution revenues
decreased $22.4 million for the transition quarter ended December 31, 2001,
largely due to a decrease in the commodity cost of gas as well as to a decrease
in weather-related sales volumes and gas usage volumes. For the quarter, weather
that was 30.1 percent warmer than the same period last year contributed to a
29.1 percent decrease in residential sales volumes and a 34.3 percent decrease
in small commercial and industrial customer sales volumes. Transportation
volumes decreased 6.3 percent primarily due to reduced consumption resulting
from a general economic weakness in the transition period. Lower commodity gas
prices along with decreased gas purchase volumes contributed to a 32.5 percent
decrease in cost of gas for the quarter.
O&M expense increased 3.2 percent in the transition quarter primarily due to
increased bad debt expense partially offset by reduced labor-related and
marketing costs. A 7.9 percent increase in depreciation expense in the
three-months ended December 31, 2001 primarily was due to normal growth of the
utility's distribution system. Taxes other than income taxes primarily reflected
various state and local business taxes as well as payroll-related taxes. State
and local business taxes generally are based on gross receipts and fluctuate
accordingly.
DECEMBER 31, December 31,
Three months ended (in thousands) 2001 2000
------------ ------------
Natural gas transportation and sales revenues $ 96,678 $ 119,126
Cost of natural gas (45,651) (67,679)
Revenue taxes (4,969) (6,281)
-------- ---------
Natural gas transportation and sales margin $ 46,058 $ 45,166
-------- ---------
Natural gas sales volumes (MMcf)
Residential 5,128 7,230
Commercial and industrial-small 2,193 3,337
-------- ---------
Total natural gas sales volumes 7,321 10,567
Natural gas transportation volumes (MMcf) 12,973 13,851
-------- ---------
Total deliveries (MMcf) 20,294 24,418
-------- ---------
NON-OPERATING ITEMS
CONSOLIDATED: Interest expense in 2002 increased $1.6 million and was influenced
by increased short-term debt at Energen, primarily related to Energen Resources'
acquisition of Permian Basin properties in April 2002, as well as Alagasco's
issuance of $40 million of 6.25% Notes and $35 million of 6.75% Notes in August
2001 (the Notes). Fiscal 2001 interest expense increased $4.3 million primarily
due to $150 million of medium term notes (MTNs) issued by Energen in December
2000 and, in part, from the issuance of the Notes. The average daily outstanding
balance under short-term credit facilities was $85.6 million in 2002. The
average daily outstanding balance under short-term credit facilities was $80.7
million in fiscal year 2001 as compared to $146.8 million in fiscal year 2000.
The Company's effective tax rates in 2002, 2001 and 2000 were lower than
statutory federal tax rates primarily due to the recognition of nonconventional
fuels tax credits and the amortization of investment tax credits.
Nonconventional fuels tax credits were generated annually on qualified
production through December 31, 2002.
20
Income tax expense increased in 2002 and 2001 primarily due to higher pre-tax
income. The Company recognized $14.2 million, $13.6 million and $14.4 million in
nonconventional fuels tax credits in 2002, 2001 and 2000, respectively. The
nonconventional fuels tax credits are no longer generated effective December 31,
2002, due to changes in the tax law. As of December 31, 2002, the amount of
minimum tax credit that has been previously recognized and can be carried
forward indefinitely to reduce future regular tax liability is $64.8 million.
TRANSITION PERIOD: Interest expense for the Company increased $0.4 million for
the transition quarter. Influencing the increase in interest expense for the
transition quarter was the issuance of MTNs issued by Energen in December 2000
and the issuance of the Notes by Alagasco in August 2001. The proceeds from the
Notes were used for repayment of borrowings under Energen's short-term credit
facilities incurred as a result of the growth at Energen Resources and for
general corporate purposes at Alagasco.
The Company's effective tax rate was lower than the statutory federal tax rate
primarily due to the recognition of nonconventional fuels tax credits and the
amortization of investment tax credits. Income tax expense decreased in quarter
comparisons primarily as a result of lower consolidated pre-tax income slightly
offset by higher nonconventional fuels tax credits of $1.2 million. The increase
in credit recognition reflected the annualized effective rate applied on an
interim basis in the three months ended December 31, 2000, as compared to the
transition period which was presented as a stand alone tax period in the current
quarter. The effective tax rate utilized in computing income tax expense
reflects financial recognition of $3.5 million of nonconventional fuels tax
credits as produced during the transitional quarter.
FINANCIAL POSITION AND LIQUIDITY
The Company's net cash from operating activities totaled $213.5 million, $156.5
million and $105 million in 2002, 2001 and 2000, respectively. In 2002,
operating cash flow benefited from significantly higher production volumes
related to Energen Resources' property acquisition and decreased storage
inventory balances at Alagasco. Operating cash flow in 2001 benefited from
significantly higher realized commodity prices at Energen Resources. Working
capital needs at Alagasco in 2001 were affected by increased gas costs and
colder-than-normal weather resulting in higher storage inventory balances. Other
working capital items, which primarily are the result of changes in throughput
and the timing of payments, combined to create the remaining increases for all
years.
During 2002, the Company made net investments of $268.2 million. Energen
Resources invested $184.2 million for property acquisitions, $122.5 million for
the development of proved properties and $0.1 million for exploration. In April
2002, Energen Resources completed its purchase of oil and gas properties located
in the Permian Basin in west Texas from First Permian, L.L.C. (First Permian)
for approximately $120 million in cash and 3,043,479 shares of the Company's
common stock. The total acquisition approximated $184 million and added 227 Bcfe
of reserves. Energen Resources drilled 232 gross development wells incurring
approximately $77 million. Energen Resources sold or traded certain properties
during the current year, resulting in cash proceeds of $17 million. Utility
expenditures in 2002 totaled $65.8 million and primarily represented system
distribution expansion and support facilities, including, information technology
application projects. Cash used in investing activities totaled $174.4 million
in 2001. During fiscal 2001, Energen Resources invested $34.3 million for
property acquisitions, $103.6 million for development of proved properties and
$1.2 million for exploration. Energen Resources drilled 140 gross development
wells spending approximately $70 million. Energen Resources sold or traded
certain properties during fiscal 2001, resulting in cash proceeds of $17.3
million. Utility expenditures for fiscal 2001 totaled $56.1 million, including
approximately $3 million for a municipal acquisition. Cash used in investing
activities totaled $131.7 million in 2000. Energen Resources invested $2.4
million for property acquisitions, $66.7 million for development and $1.2
million for exploration during fiscal 2000. Energen Resources drilled 141 gross
development wells incurring approximately $38 million. Utility expenditures in
2000 totaled $67.1 million.
During 2002, the Company added approximately 162 Bcfe of reserves. These reserve
additions are primarily the result of unit downspacing, which increases the
number of available drilling locations, for certain wells in the Black Warrior
and San Juan basins. Energen Resources' added approximately 50 Bcfe and 76 Bcfe
of reserves in fiscal year 2001 and 2000, respectively.
21
Net cash provided by financing activities totaled $53 million in 2002. In the
current year, the Company utilized $85.9 million in short-term credit
facilities to finance Energen Resources' acquisition strategy. Long-term debt
was reduced by $21.2 million, including the retirement of the Series 1993 Notes
for $7.8 million. Net cash provided by financing activities totaled $19.4
million in 2001. In August 2001 Alagasco issued 6.25% Notes for $40 million,
redeemable September 1, 2016, and 6.75% Notes for $35 million, redeemable
September 1, 2031, and in December 2000, Energen issued $150 million of
long-term debt redeemable December 15, 2010. The $223.8 million in net proceeds
were used to repay short-term borrowings incurred to finance Energen Resources'
growth activities and to repay additional borrowings by the utility as a result
of higher capital expenditures related to replacement of liquifaction equipment
and for general corporate purposes. The proceeds also were used to reduce
long-term debt by $36.3 million, including the retirement of the 8% Debentures
for $18.3 million. Net cash used in financing activities totaled $114.9 million
in 2000 resulting primarily from fluctuations in the amount and timing of
short-term debt at year-end. The Company borrowed $140.9 million at September
30, 1999 to invest in short-term federal obligations for tax planning purposes
that were sold in early October 2000 with the proceeds used to repay the
related debt. For each of the years, net cash used in financing activities also
reflected dividends paid to common stockholders and the issuance of common
stock through the dividend reinvestment and direct stock purchase plan and the
employee savings plans.
TRANSITION PERIOD: Cash flows from operations for the transition quarter were
$21.4 million compared to $20.7 million in the three months ended December 31,
2000. The decreased net income during the period was offset by changes in
working capital items, which are highly influenced by throughput, changes in
weather, and timing of payments.
The Company had a net investment of $35.7 million through the three months
ended December 31, 2001, primarily in additions of property, plant and
equipment. Energen Resources invested $25.1 million in capital expenditures
primarily related to the development of oil and gas properties. Utility capital
expenditures totaled $12.9 million in the quarter and primarily represented
system distribution expansion and support facilities. The Company had cash
proceeds of $2.3 million resulting from the sale of certain properties during
the transition period.
The Company's financing activities provided $15.5 million for the transition
quarter in net cash flows. Increased borrowings under Energen's short-term
credit facilities were used to finance Energen Resources' acquisition strategy
and general corporate needs at Alagasco.
CAPITAL EXPENDITURES
OIL AND GAS OPERATIONS: Energen Resources spent $546.6 million for capital
projects during the year ended December 31, 2002, the three months ended
December 31, 2001 and the years ended September 30, 2001 and 2000, $12.1
million of which was charged to income as exploration expense primarily due to
the writedown of a portion of an unproved leasehold. Property acquisition
expenditures totaled $221.2 million, development activities totaled $317.5
million, and exploratory expenditures totaled $2.7 million.
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------- ------------- -------------
Capital and exploration expenditures for:
Property acquisitions $184,177 $ 319 $ 34,316 $ 2,436
Development 122,494 24,757 103,574 66,717
Exploration 104 228 1,190 1,150
Other 1,880 464 1,477 1,343
-------- ------- -------- -------
Total 308,655 25,768 140,557 71,646
Less exploration expenditures charged
to income 3,179 716 3,671 4,556
-------- ------- -------- -------
Net capital expenditures $305,476 $25,052 $136,886 $67,090
======== ======= ======== =======
22
NATURAL GAS DISTRIBUTION: During the year ended December 31, 2002, the three
months ended December 31, 2001 and the years ended September 30, 2001 and 2000,
Alagasco invested $201.9 million for capital projects: $124 million for normal
expansion, replacements and support of its distribution system, $74.9 million
for support facilities, including the replacement of liquifaction equipment and
the development and implementation of information systems, and $3 million to
purchase a municipal gas system.
Three Months
YEAR ENDED Ended Year Ended Year Ended
DECEMBER 31, December 31, September 30, September 30,
(in thousands) 2002 2001 2001 2000
------------ ------------ ------------- -------------
Capital and expenditures for:
Renewals, replacements,
system expansion and other $43,029 $ 8,839 $36,340 $35,774
Support facilities 22,786 4,034 16,733 31,299
Municipal gas system acquisition -- -- 3,017 --
------- ------- ------- -------
Total $65,815 $12,873 $56,090 $67,073
======= ======= ======= =======
FUTURE CAPITAL RESOURCES AND LIQUIDITY
The Company plans to continue to implement its diversified growth strategy that
focuses on expanding Energen Resources' oil and gas operations through the
acquisition of producing properties with development potential while
maintaining the strength of the Company's utility foundation. For the five
calendar years ended December 31, 2002, Energen's EPS grew at an average
compound rate of 11.5 percent a year. Over the next five years, Energen is
targeting an average EPS growth rate over each rolling five-year period of 7
percent to 8 percent a year.
To finance Energen Resources' investment program, the Company expects to
utilize its short-term credit facilities to supplement internally generated
cash flow, with long-term debt and equity providing permanent financing.
Energen currently has available short-term credit facilities of $267 million to
help finance its growth plans and operating needs. As an acquisition company,
access to capital is an integral part of the Company's business plan. The
Company regularly provides information to corporate rating agencies related to
current business activities and future performance expectations. In February
2003, Moody's Investors Service confirmed Energen's debt rating as Baa1 and
Alagasco's debt rating as A1. Standard and Poor's last update in June 2002,
confirmed Energen's and Alagasco's rating as A- with a stable outlook. While
the Company expects to have ongoing access to it's short-term credit facilities
and the broader long-term markets, continued accessibility could be affected by
future economic and business conditions. Energen's management plans to utilize
increases in cash flows to help finance Energen Resources' acquisition
strategy.
In 2003, Energen Resources plans to invest approximately $158 million,
including $47 million in property acquisitions and related development and $111
million in other development and exploratory activities. Included in this $111
million is approximately $65 million for the development of previously
identified proved undeveloped reserves and exploratory exposure of
approximately $3 million. Capital investment at Energen Resources in 2004 is
expected to approximate $123 million for property acquisitions and related
development and $68 million for other development and exploration. Of this $68
million, development of previously identified proved undeveloped reserves is
estimated to be $35 million and exploratory exposure is estimated to be $3
million. Energen Resources' capital investment for oil and gas activities over
the five-year period ending December 31, 2007 is estimated to be approximately
$835 million, with $590 million for property acquisitions and related
development, $222 million for other development and $23 million for exploratory
and other activities. During the five year period, Energen Resources
anticipates spending approximately $120 million on development of previously
identified proved undeveloped reserves and incurring approximately $15 million
in exploratory exposure. During this period, the Company expects to issue
approximately $75 million in long-ter