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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES AND EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1996
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COMMISSION IRS EMPLOYER
FILE STATE OF IDENTIFICATION
NUMBER REGISTRANT INCORPORATION NUMBER
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1-7810 Energen Corporation Alabama 63-0757759
2-38960 Alabama Gas Corporation Alabama 63-0022000
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2101 Sixth Avenue North
Birmingham, Alabama 35203
(205) 326-2700
Securities Registered Pursuant to Section 12(b) of the Act:
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TITLE OF EACH CLASS EXCHANGE ON WHICH REGISTERED
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Energen Corporation Common Stock, $0.01 par value New York Stock Exchange
Energen Corporation Preferred Stock Purchase Rights New York Stock Exchange
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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
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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. (X)
Aggregate market value of the voting stock held by non-affiliates of the
registrants as of November 13, 1996:
Energen Corporation $295,327,463
Indicate number of shares outstanding of each of the registrant's classes of
common stock as of November 13, 1996:
Energen Corporation 11,250,570 shares
Alabama Gas Corporation 1,972,052 shares
Alabama Gas Corporation meets the conditions set forth in General Instruction
J(1) (a) and (b) of Form 10-K and is therefore filing this form with the
reduced disclosure format pursuant to General Instruction J(2).
DOCUMENTS INCORPORATED BY REFERENCE
- - Energen Corporation Proxy Statement to be filed on or about December 21,
1996 (Part III, Item 10-13)
- - Portions of Energen Corporation 1996 Annual Report to Stockholders are
incorporated by reference into Part II, Items 5, 6, 7, and 8 of this report
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ENERGEN CORPORATION
1996 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
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PAGE
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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 . . . . . . . . . . 12
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . 12
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
PART III
Item 10. Directors and Executive Officers of the Registrants . . . . . . . . . . . . . . . . . . 13
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . 13
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . 13
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . . 14
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This Form 10-K is filed on behalf of Energen Corporation (Energen or the
Company) and Alabama Gas Corporation (Alagasco).
PART I
ITEM 1. BUSINESS
GENERAL
Energen is a diversified energy holding company engaged primarily in natural
gas distribution and the exploration and production of natural gas and oil.
Energen was incorporated in Alabama in 1978 in connection with the
reorganization of its largest subsidiary, Alagasco. Alagasco was formed in
1948 by the merger of Alabama Gas Company into Birmingham Gas Company, the
predecessors of which had been in existence since the late 1800's. Alagasco
became a public company in 1953.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The information required by this item is incorporated by reference from Note 12
Industry Segment Information to the Consolidated Financial Statements of the
1996 Annual Report to Stockholders, and is attached herein as Part IV, Item 14,
Exhibit 13.
NARRATIVE DESCRIPTION OF BUSINESS
- - NATURAL GAS DISTRIBUTION
GENERAL: Alagasco, Energen's principal subsidiary, is the largest natural
gas distribution utility in the state of Alabama. Alagasco purchases
natural gas through interstate and intrastate suppliers and distributes the
purchased gas through its distribution facilities for sale to residential,
commercial, industrial and other end-users of natural gas. Alagasco also
provides transportation services to industrial and commercial customers
located on its distribution system. These transportation customers, acting
on their own or using Alagasco as their agent, purchase gas directly from
producers or other suppliers and arrange for delivery of the gas into the
Alagasco distribution system. Alagasco then charges a fee to transport this
customer-owned gas through its distribution system to the customer's
facility.
Alagasco's service territory is located primarily in central and north
Alabama and includes over 175 communities in 30 counties. Birmingham, the
largest city in Alabama, and Montgomery, the state capital, are served by
Alagasco. The counties in which Alagasco provides service have an aggregate
area of more than 22,000 square miles and include the service territories of
various municipal gas distribution systems.
The aggregate population of the counties served by Alagasco is estimated to
be 2.4 million. During 1996 Alagasco served an average of 418,486
residential customers, 34,028 small commercial and industrial customers, and
54 large commercial and industrial customers. The Alagasco distribution
system includes approximately 8,800 miles of main, more than 9,600 miles of
service lines, odorization and regulation facilities, and customer meters.
Alagasco also operates two liquefied natural gas facilities which it uses to
meet peak demands.
APSC REGULATION: As 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 for the fourth time on October 7, 1996, for a five-year period
through January 1, 2002. Under the terms of that extension, RSE will
continue after January 1, 2002, unless, after notice to the Company and a
hearing, the Commission votes to either modify or discontinue its operation.
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Under RSE, the APSC conducts quarterly reviews to determine, based on
Alagasco's projections and fiscal year-to-date performance, whether
Alagasco's return on equity for the fiscal year will be within the allowed
range of 13.15 percent to 13.65 percent. Reductions in rates can be made
quarterly to bring the projected return within the allowed range; increases,
however, are allowed only once each fiscal 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. If the change
in O&M expense per customer falls within 1.25 percentage points above or
below the Consumer Price Index For All Urban Customers (index range), no
adjustment is required. If, however, the change in O&M expense per customer
exceeds the index range, three-quarters of the difference 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. Under RSE as extended, an $8.2 million annual increase in
revenue became effective December 1, 1995, and a $1.3 million decrease in
revenue became effective October 1, 1996.
Alagasco calculates a temperature adjustment to customers' monthly bills to
remove the effect of departures from normal temperature on Alagasco's
earnings. The calculation is performed monthly, and the adjustments to
customers' bills are made in the same billing cycle the weather variation
occurs.
Alagasco's rate schedules for natural gas distribution charges contain a Gas
Supply Adjustment (GSA) rider, which permits the pass-through to customers
of changes in the cost of gas supply, including Gas Supply Realignment (GSR)
surcharges imposed by Alagasco's suppliers resulting from changes in gas
supply purchases related to the implementation of Federal Energy Regulatory
Commission (FERC) Order 636. On October 7, 1996, the APSC issued an order
providing for the refund to customers of approximately $17.1 million,
including interest, of supplier refunds. The Order provides that refunds
shall be returned to customers prior to January 31, 1997. These refunds were
collected from a variety of sources and most relate to the settlement of
rate case and FERC Order 636 proceedings of Southern Natural Gas Company
(Southern) as described herein.
On September 9, 1996, the APSC approved Alagasco's application to issue $25
million of debt, a portion of which will be used to fund the supplier
refunds discussed above. On June 12, 1995, Alagasco received approval from
the APSC to issue $50 million of debt, a portion of which was used to redeem
all of Alagasco's 9 percent debentures and 11 percent First Mortgage Bonds.
In connection with the early call of the redeemed debt, Alagasco paid an
early call premium of approximately $1.3 million. Because the APSC
authorized Alagasco to collect the early call premium through customer
rates, a regulatory asset of $1.3 million was recorded at September 30,
1995, and the amounts were collected during fiscal 1996.
In accordance with APSC-directed regulatory accounting procedures, Alagasco
in 1989 began returning to customers excess utility deferred taxes which
resulted from a reduction in the federal statutory tax rate from 46 percent
to 34 percent using the average rate assumption method. This method provides
for the return to ratepayers of excess deferred taxes over the lives of the
related assets. In 1993 those excess taxes were reduced as a result of a
federal tax rate increase from 34 percent to 35 percent. Remaining excess
utility deferred taxes of $2.7 million are being returned to ratepayers over
approximately 14 years. At September 30, 1996 and 1995, regulatory
liabilities of $5 million and $6 million, respectively, were included in the
financial statements related to income taxes.
FERC REGULATION: On March 15, 1995, Southern filed a comprehensive
settlement with the FERC in the form of a Stipulation and Agreement (the
Settlement) to resolve all issues in Southern's six pending rate cases, as
well as to resolve all GSR and transition cost issues resulting from the
implementation of FERC Order 636. Alagasco was a supporting party to the
Settlement. On April 11, 1996, the FERC issued its Order on Rehearing
approving the Settlement with minor modifications. The Settlement, as
approved by FERC, provides for the following: (1) the resolution of all cost
of service and rate design issues in Southern's six pending rate cases and
the establishment of reduced rates for the purpose of calculating rate case
refunds; (2) the implementation of reduced settlement rates for supporting
parties commencing March 1, 1995; (3) the resolution of all GSR and other
transition cost issues resulting from FERC Order 636; (4) lower GSR cost
recovery through the reduction and earlier payout of GSR costs; (5) a
three-year moratorium on general rate increases; and (6) the resolution and
disposition of all rate case
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and GSR refunds for supporting parties. With respect to this last point, the
Settlement provides that all rate case refunds will be used to offset a
portion of Southern's remaining GSR liability. In addition, as a result of
the recalculated GSR surcharges for the period January 1, 1994, to February
28, 1995, Southern refunded over-collected GSR costs. As a result of this
FERC order, Alagasco received other refunds based on contracts with other
suppliers whose prices were tied to Southern's rates. In total, $17.1
million will be refunded to customers prior to January 31, 1997, and
includes amounts received from Southern, other suppliers and accrued
interest.
The Settlement, as approved by FERC, resolves all issues relating to GSR and
other transition costs with respect to supporting parties. Alagasco
estimates that it has a remaining GSR liability of approximately $0.8
million to be paid through December 1997 and approximately $1.4 million in
other transition costs to be paid through June 1998. Because these costs
will be recovered in full from its customers, Alagasco recorded regulatory
assets of $2.2 million and $5 million at September 30, 1996 and 1995,
respectively.
GAS SUPPLY: The Alagasco distribution system is connected to and has firm
transportation contracts with two major interstate pipeline
systems--Southern and Transcontinental Gas Pipe Line Corporation. Effective
November 1, 1993, Alagasco's pre-Order 636 contract demand and firm
transportation with Southern converted to 250,924 Mcf (thousand cubic feet)
per day of No-Notice Firm Transportation service for a period of 15 years,
91,946 Mcf per day of Firm Transportation service for 15 years, and 50,000
Mcf per day of Firm Transportation for five years. Southern also unbundled
its existing storage capacity. Alagasco's pro rata share of this storage is
12,426,687 Mcf. Alagasco has a maximum withdrawal rate from storage of
250,924 Mcf per day and a maximum injection rate into storage of 95,590 Mcf
per day. The Transco firm transportation contract, which expires in 2001,
provides for maximum daily firm transportation of up to 100,000 Mcf. Thus
the Company has a peak day firm interstate pipeline transportation capacity
of 492,870 Mcf per day.
Alagasco has replaced the sales service formerly provided by Southern with
purchases from various gas producers and marketers including affiliates of
Southern and Transco and from certain intrastate producers including Basin
Pipeline Corp., an Energen subsidiary. Alagasco has contracts in place to
purchase up to a total of 286,776 Mcf per day of firm supply, of which
241,946 is supported by firm transportation on the Transco and Southern
systems, 14,830 Mcf provides excess supply on the Southern system, and
30,000 Mcf is purchased at the city gate from intrastate suppliers. This
volume, along with Alagasco's maximum withdrawal from storage of 250,924 Mcf
per day and 200,000 Mcf per day of liquefied natural gas peak shaving
capacity, gives Alagasco a peak day firm supply of 722,870 Mcf per day.
Alagasco also utilizes the Southern and Transco pipeline systems to access
spot market gas in order to supplement its firm system supply and serve its
industrial transportation customers.
COMPETITION AND PRICING: The price of natural gas is a significant
marketing factor in the territory served by Alagasco; propane, coal and fuel
oil are readily available, and many major industrial customers have the
capability to switch to alternate fuels. In the residential and small
industrial and commercial markets, electricity is the principal competitor.
Natural gas service available to Alagasco customers generally falls into two
categories -- interruptible and firm. Interruptible service is
contractually subject to interruption by Alagasco for various reasons, the
most common of which is curtailment of industrial customers during periods
of peak residential heating demand on the Alagasco system. Firm service is
generally not subject to interruption and, therefore, is more expensive than
interruptible service. Firm service is generally provided to residential
and small commercial and industrial customers. Interruptible service is
generally provided to large commercial and industrial customers which
typically have the capacity to reduce consumption by adjusting their
production schedules or by switching to alternate fuels during periods of
interruption. Deliveries of sales and transportation gas totaled 111,422
MMcf (million cubic feet) in 1996.
In 1994, capitalizing on federally mandated changes in the natural gas
industry, Alagasco implemented the "P" Rate. This tariff allows the utility
to, in effect, release available pipeline capacity thereby reducing pipeline
transportation costs for its 275 transportation customers. The lower costs
help prevent bypass. Also, because
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revenue received from capacity release reduces core market gas costs,
Alagasco's competitive position in the residential and small commercial
markets is enhanced as well.
Alagasco has a Competitive Fuel Clause (CFC) as part of its rate tariff
which allows Alagasco to adjust large commercial and industrial prices on a
case-by-case basis to compete with either alternate fuels or alternate
sources of gas. The GSA rider to Alagasco's tariff increases the rates paid
by other customers to recover the reduction in rates allowed under the CFC
because the retention of any customer, particularly large commercial and
industrial, benefits all customers by recovering a portion of the system's
fixed cost.
Alagasco also has a Transportation Tariff (the Tariff) which allows the
Company to transport gas for customers rather than buying and reselling gas
to them. The Tariff is based on Alagasco's gas sales profit margin so that
Alagasco's net income is not affected whether it transports or sells gas.
The Tariff also may be adjusted under the CFC. Of Alagasco's total large
commercial and industrial customer deliveries during 1996, 99.95 percent
(46,207 MMcf) was from transportation of customer-owned gas.
GROWTH: Alagasco has supplemented traditional service area growth with
acquisitions of municipally-owned gas distribution systems. Since 1985
Alagasco has acquired 22 such systems, three of which were acquired in
fiscal 1996 initially adding over 1,800 customers. More than 43,000
customers have been added through initial system purchases and subsequent
customer additions, as Alagasco has increased the relatively low saturation
rates in the acquired areas through a variety of marketing efforts including
offering natural gas service to propane customers already situated on the
municipal system lines, extending the acquired municipal system into nearby
neighborhoods that desire natural gas service, and marketing natural gas
appliances to existing and new customers. Approximately 80 municipal
systems, representing about 250,000 customers remain in Alabama, and many
are located in or near Alagasco's existing service territory. The Company is
optimistic that additional acquisition opportunities will arise in the
future.
WEATHER: Alagasco's gas distribution business is highly seasonal since a
material portion of Alagasco's total sales and delivery volumes is to
customers whose use varies depending upon temperature, principally
residential, small commercial and small industrial customers. Alagasco's
rate tariff includes a temperature adjustment rider which is designed to
mitigate the effect of departures from normal temperature on Alagasco's
earnings. The calculation is performed monthly and adjustments are made to
customers' bills in the actual month the weather variation occurs.
ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight former
manufactured gas plant sites, of which it still owns four, and five
manufactured gas distribution sites, of which it still owns one. A
preliminary investigation of the sites does not indicate the present need
for remediation activities. Management expects that should remediation of
any such sites be required in the future, Alagasco's share, if any, of such
costs will not materially affect the results of operations or financial
condition of Alagasco.
OTHER: For a discussion of risks inherent in the Company's businesses see
Management's Discussion and Analysis in the 1996 Annual Report to
Shareholders, page 30, which is attached herein as Part IV, Item 14, exhibit
13.
- - OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Energen's oil and gas exploration and production activities are conducted by
its subsidiary, Taurus Exploration, Inc. (Taurus) and involve the
acquisition, development, exploration and production of natural gas and oil
from conventional and nonconventional reservoirs in the continental United
States. Taurus's remaining recoverable reserves at the end of fiscal 1996
totaled 250,867 million cubic feet equivalents (MMcfe) and are located
primarily in Alabama, Louisiana, Texas and the Gulf of Mexico.
As Energen's dominant growth vehicle, Taurus is continuing its strategic
focus on acquiring conventional oil and gas producing properties with
development potential and supplementing returns with relatively low-risk
Gulf of Mexico exploration and related development. Beginning with the 1996
fiscal year, Energen embarked on an aggressive, five- year diversified
growth strategy which calls for the Company to invest through Taurus $400
million
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in producing property acquisitions and related development and $100 million
in exploration and related development.
In implementing Energen's growth strategy, Taurus works with a variety of
experienced industry partners in its acquisition and exploration activities.
Taurus also is working to increase its internal generation of acquisition
opportunities. To help minimize risk, Taurus takes small working interest
positions in numerous exploratory prospects rather than a large position in
a few. Taurus also utilizes the natural gas and oil futures markets as well
as fixed-price contracts as defensive mechanisms to mitigate the impact of
commodity price volatility on targeted returns of reserve acquisitions and
to manage overall price volatility on other production.
The first year of implementation of Energen's diversified growth strategy
resulted in Taurus investing $108 million for the acquisition of eight
producing properties with development potential and participating in 12
successful exploratory and development wells in the Gulf of Mexico. Net
reserve additions totaled 171,801 MMcfe, production increased 60 percent to
16,118 MMcfe, and the average sales price per MMcfe was $1.97.
Taurus also serves as the operator of extensive Black Warrior Basin coalbed
methane properties for its own interests and those of its partners, and also
provides third-party operations. Since making the transition away from the
development of new coalbed methane projects in the early 1990s, Taurus has
continued to operate coalbed methane wells as a profitable business activity
but looks to the acquisition, exploration and development of oil and gas
reserves for long-term growth.
PROPERTY ACQUISITIONS AND DEVELOPMENT: Taurus's largest property acquisition
in fiscal 1996 was the $61 million purchase of 105 Bcf of coalbed methane
reserves in Alabama from Burlington Resources Inc. Part of Burlington's
accelerated divesture program, these Black Warrior Basin wells cover 19,000
gross acres adjacent to existing coalbed methane interests of Taurus's in
west central Alabama. Substantially all of these long-lived coalbed methane
reserves are proved producing and complemented well Taurus's other reserve
acquisitions which featured a greater amount of behind-pipe and proved
undeveloped reserves. Production from 43 of the more than 100 wells
qualifies for the nonconventional fuels tax credit, which presently is
valued at $1 per Mcf of production and increases annually with inflation.
Through its partnership with Sonat Exploration Company, a subsidiary of
Birmingham-based Sonat Inc., Taurus invested $28 million in four
conventional property acquisitions during fiscal 1996. Three of the
properties are located in Louisiana and the other is located in the Gulf of
Mexico, offshore Louisiana and Texas. Taurus's working interest in these
projects ranges from one-third to 40 percent. Taurus estimates its
development costs related to these acquisitions will total approximately $20
million over the next three to four years. Taurus joined Sonat Exploration's
ongoing reserve acquisition efforts in the summer of 1995 through a
three-and-a-half year agreement and plans to invest $25 million to $50
million annually with Sonat in calendar years 1996, 1997 and 1998. Related
development drilling may require additional investment on the part of Taurus
over the ensuing five years of approximately 50 cents for each acquisition
dollar.
In September 1996, Taurus purchased a 75 percent working interest in the
Odem Field in south Texas from Bargo Energy Company and Moran Resources
Company and acquired estimated proved reserves of 21 Bcfe for $15 million.
Taurus's share of future development costs could approximate $4 million.
Early in fiscal 1996, Taurus made a small acquisition through its joint
venture with PMC Reserve Acquisition Company and subsequently purchased the
interest of another participant in PMC's acquisition program. In September
1996, PMC sold its oil and gas properties; Taurus elected to sell its
related interests of 11 Bcfe and realized a $3.2 million gain on its
investment. As part of our ongoing business activities, Taurus may be
involved, from time to time, in the sale of developed and undeveloped
properties as a source of revenue as a result of, but not limited to,
disposing of marginal assets and accepting offers where the buyer gives
greater value to a property than Taurus's technical staff.
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EXPLORATION AND DEVELOPMENT: Taurus invested $18 million in offshore
exploration and related development during 1996. Through existing
partnership arrangements with United Meridian Corporation (UMC) and King
Ranch Oil & Gas, Taurus participated in 12 successful exploratory and
development wells, adding 5 Bcf of natural gas to its proved reserves.
Taurus utilizes several avenues to ensure a continuing flow of high quality
exploratory prospects, including its participation in UMC's offshore
exploratory program, a multi-year 3-D seismic joint venture with King Ranch
and Holley Petroleum, Inc., covering 200 offshore Texas blocks, and other
offshore lease sales with various industry partners.
While primarily focusing on Gulf of Mexico exploration, Taurus did acquire
in fiscal 1996 a 25 percent working interest in Sonat Exploration's
exploratory efforts in the North Crowley field in Louisiana. This field also
contains producing properties and was one of the four acquisitions made
through Taurus's joint agreement with Sonat Exploration. The field contains
8,000 gross undeveloped acres.
COALBED METHANE OPERATIONS: Taurus's nonconventional gas strategy is to
focus on operating the large projects in which it has a working interest and
operating for others. Taurus is the operator of approximately 1,140 coalbed
methane wells, including wells in a project owned by TECO Coalbed Methane,
Inc., one of Taurus's joint venture partners in other coalbed methane
projects. Under the terms of the TECO agreement, Taurus provides technical,
administrative and operating services for a fee and receives additional
compensation based on the project's profitability.
Most of the gas produced from the coalbed methane wells in which Taurus has
an interest is being sold under long-term contracts which provide markets
for 100 percent of the wells' production capacity.
ENVIRONMENTAL MATTERS: Taurus is subject to various environmental
regulations. Management believes that Taurus is in compliance with currently
applicable standards of the environmental agencies to which it is subject
and that potential environmental liabilities, if any, are minimal. Also, to
the extent Taurus has operating agreements with various joint venture
partners, environmental costs, is any, would be shared proportionately.
OTHER: For a discussion of risks inherent in the Company's businesses see
Management's Discussion and Analysis in the 1996 Annual Report to
Shareholders, page 30, which is attached herein as Part IV, Item 14, exhibit
13.
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- - INTRASTATE GAS GATHERING AND TRANSMISSION
Energen operates an intrastate gas pipeline and gathering system through its
subsidiary, Basin Pipeline Corp. (Basin). Basin's pipeline and gathering
facilities primarily serve certain Taurus coalbed methane properties.
EMPLOYEES
The Company has 1,437 employees; Alagasco employs 1,296; Taurus employs 129;
and Energen's other subsidiaries employ 12.
ITEM 2. PROPERTIES
The corporate headquarters of Energen, Alagasco and Taurus are located in
leased office space in Birmingham, Alabama.
The properties of Alagasco consist primarily of its gas distribution system,
which includes more than 8,800 miles of main, more than 9,600 miles of service
lines, odorization and regulation facilities, and customer meters. Alagasco
also has two liquefied natural gas facilities, eight division offices, nine
payment centers, six district offices, nine service centers, and other related
property and equipment, some of which are leased by Alagasco. For further
description of Alagasco's properties, see discussion under Item I--Business.
For a description of Taurus's oil and gas properties, see the discussion under
Item 1--Business. Information concerning Taurus's production, reserves and
development is included in Note 12, Oil and Gas Producing Activities
(unaudited) to the Consolidated Financial Statements which is incorporated by
reference from the 1996 Annual Report to Stockholders and included in Part IV,
Item 14, Exhibit 13, herein. The proved reserve estimates are consistent with
comparable reserve estimates filed by Taurus with any federal authority or
agency.
ITEM 3. LEGAL PROCEEDINGS
Energen, Alagasco and their 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 Alagasco. It should be noted, however, that Energen,
Alagasco and their affiliates conduct business in Alabama and other
jurisdictions in which the magnitude and frequency of punitive damage awards
bearing little or no relation to culpability or actual damages continue to rise
making it increasingly 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 1996.
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EXECUTIVE OFFICERS OF THE REGISTRANTS
ENERGEN CORPORATION
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Name Age Position (1)
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Rex J. Lysinger 59 Chairman of the Board and Chief Executive Officer (2)
Wm. Michael Warren, Jr. 49 President and Chief Operating Officer (3)
Geoffrey C. Ketcham 45 Executive Vice President, Chief Financial Officer and
Treasurer (4)
Dudley C. Reynolds 43 General Counsel and Secretary (5)
Gary C. Youngblood 53 Executive Vice President and Chief Operating Officer of
Alagasco (6)
James T. McManus 38 Executive Vice President and Chief Operating Officer of
Taurus (7)
John A. Wallace 52 Senior Vice President--Methane of Taurus (8)
J. David Woodruff, Jr. 40 Vice President--Legal and Assistant Secretary and Vice
President--Corporate Development (9)
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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 its Board of Directors.
(2) Served as Vice President of Alagasco from July 1975 to January
1977, when he was elected President. Elected President of Energen
upon its formation in 1978. Elected Chairman of the Board of
Energen and its subsidiaries September 1982. Currently Chairman of
the Board of Energen and all subsidiaries and Chief Executive
Officer of Energen. Serves as a Director of Energen and each of
its subsidiaries.
(3) Served as Senior Vice President and General Counsel of Alagasco
from September 1983 to October 1984, when he was elected President
and Chief Operating Officer of that corporation. Elected Executive
Vice President of Energen June 1987 and elected President and Chief
Operating Officer of Energen April 1991. Elected President and
Chief Operating Officer of all Energen subsidiaries January 1992.
Elected Chief Executive Officer of Alagasco and Taurus effective
October 1995. Serves as a Director of Energen and each of its
subsidiaries.
(4) Elected Controller of Alagasco November 1981, Vice President and
Controller June 1984, Vice President--Finance and Planning of
Alagasco June 1985 and Vice President--Planning of Energen August
1986. Elected Vice President--Finance, Chief Financial Officer and
Treasurer of Energen and each of its subsidiaries June 1987.
Elected Senior Vice President--Finance, Chief Financial Officer and
Treasurer of Energen and each of its subsidiaries April 1989.
Elected Executive Vice President, Chief Financial Officer and
Treasurer of Energen and each of its subsidiaries April 1991.
10
<PAGE> 11
(5) Served as Staff Attorney for Energen and its subsidiaries to
November 1984, when he was named Senior Attorney. Elected
Assistant Secretary in 1985 and Secretary effective September 1986.
Elected Vice President--Legal and Secretary of Energen and each of
its subsidiaries June 1987. Elected General Counsel and Secretary
of Energen and each of its subsidiaries April 1991.
(6) Served as District Manager--Birmingham District until June 1985,
when he was elected Vice President--Birmingham Operations; Elected
Senior Vice President--Administration of Alagasco April 1991.
Elected Executive Vice President of Alagasco October 1993.
Elected Chief Operating Officer of Alagasco effective October 1995.
(7) Served as Director of Corporate Accounting of Energen until
November 1988, when he was elected Controller of Energen; Elected
Controller of Alagasco May 1989. Elected Assistant Vice
President--Corporate Development of Energen June 1990. Elected
Vice President--Finance and Corporate Development of Energen and
Vice President--Finance and Planning of Alagasco effective April
1991. Elected Executive Vice President and Chief Operating Officer
of Taurus effective October 1995.
(8) Served as Manager, Methane Development of Taurus until August 1988,
when he was elected Vice President Methane Operations of Taurus.
Elected Vice President Methane Exploration and Production of Taurus
November 1990. Elected Senior Vice President--Methane of Taurus
February 1992.
(9) Served as Staff Attorney for Alagasco from March 1986 to June 1987
when he was named Senior Attorney. Elected Assistant Vice
President--Legal and Assistant Secretary of Energen and each of its
subsidiaries November 1988. Elected Vice President--Legal and
Assistant Secretary of Energen and each of its subsidiaries April
1991. Elected Vice President--Legal, and Assistant Secretary of
Energen and each of its subsidiaries and Vice President--Corporate
Development of Energen October 1995.
11
<PAGE> 12
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
The information regarding Energen's common stock and the frequency and amount
of dividends paid during the past two years with respect to such stock is
incorporated by reference from the 1996 Annual Report to Stockholders, page 30,
and is included in Part IV, Item 14, Exhibit 13, herein. At October 28, 1996,
there were approximately 7,700 holders of record of Energen's common stock. For
restrictions on Energen's present and future ability to pay dividends, see Note
3 to the Consolidated Financial Statements which is incorporated by reference
from the 1996 Annual Report to Stockholders and included in Part IV, Item 14,
Exhibit 13, herein.
At the date of this filing, Energen Corporation owns all the issued and
outstanding common stock of Alabama Gas Corporation.
ITEM 6. SELECTED FINANCIAL DATA
The information regarding selected financial data is incorporated by reference
from the 1996 Annual Report to Stockholders, pages 54-55, and is included in
Part IV, Item 14, Exhibit 13, herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
This information is incorporated by reference from the 1996 Annual Report to
Stockholders, pages 23-30, and is included in Part IV, Item 14, Exhibit 13,
herein.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item for Energen Corporation and subsidiaries
is incorporated by reference from the 1996 Annual Report to Stockholders and is
included in Part IV, Item 14, Exhibit 13, herein. The information required by
this item for Alabama Gas Corporation is contained in Part IV, Item 14, herein.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
12
<PAGE> 13
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the executive officers of Energen is included in Part I.
The other information required by Item 10 is incorporated herein by reference
from Energen's definitive proxy statement for the Annual Meeting of
Stockholders to be held January 22, 1997. The proxy statement will be filed on
or about December 21, 1996.
ITEM 11. EXECUTIVE COMPENSATION
The information regarding executive compensation is incorporated herein by
reference from Energen's definitive proxy statement for the Annual Meeting of
Stockholders to be held January 22, 1997.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
A. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The information regarding the security ownership of the beneficial owners
of more than five percent of Energen's common stock is incorporated herein
by reference from Energen's definitive proxy statement for the Annual
Meeting of Stockholders to be held January 22, 1997.
B. SECURITY OWNERSHIP OF MANAGEMENT
The information regarding the security ownership of management is
incorporated herein by reference from Energen's definitive proxy statement
for the Annual Meeting of Stockholders to be held January 22, 1997.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related transactions is
incorporated herein by reference from Energen's definitive proxy statement for
the Annual Meeting of Stockholders to be held January 22, 1997.
13
<PAGE> 14
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
A. DOCUMENTS FILED AS PART OF THIS REPORT
(1) FINANCIAL STATEMENTS
The financial statements listed in the accompanying Index to
Financial Statements and Financial Statement Schedules are filed as
part of this report and are included in Part IV, Item 14, Exhibit 13,
herein.
(2) FINANCIAL STATEMENT SCHEDULES
The financial statement schedules listed in the accompanying Index to
Financial Statements and Financial Statement Schedules are filed as
part of this report.
(3) EXHIBITS
The exhibits listed on the accompanying Index to Exhibits are filed
as part of this report.
B. REPORTS ON FORM 8-K
(1) Form 8-K dated August 10, 1996, reporting a property acquisition by
Taurus Exploration, Inc., the Company's oil and gas exploration and
production subsidiary
(2) Form 8-K(A) dated August 10, 1996, reporting certain supplementary
financial information related to the above purchase
14
<PAGE> 15
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrants have duly caused this report to be signed
on their behalf by the undersigned thereunto duly authorized.
ENERGEN CORPORATION
(Registrant)
ALABAMA GAS CORPORATION
(Registrant)
December 16, 1996 /s/Rex J. Lysinger
- ------------------------- ----------------------------------------------
DATE Rex J. Lysinger
Chairman of the Board of Directors of Energen
and all subsidiaries, Chief Executive Officer
of Energen
15
<PAGE> 16
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed by the following persons on behalf of the Registrants
and in the capacities and on the dates indicated:
<TABLE>
<S> <C>
December 16, 1996 /s/Rex J. Lysinger
- -------------------------- --------------------------------------------------------------
DATE Rex J. Lysinger
Chairman of the Board of Directors of Energen
and all subsidiaries, Chief Executive Officer of
Energen
December 16, 1996 /s/Wm. Michael Warren, Jr.
- ---------------------------- --------------------------------------------------------------
DATE Wm. Michael Warren, Jr.
President and Director of Energen and all
subsidiaries, Chief Executive Officer of Alagasco
and Chief Operating Officer of Energen
December 16, 1996 /s/Geoffrey C. Ketcham
- ---------------------------- --------------------------------------------------------------
DATE Geoffrey C. Ketcham
Executive Vice President, Chief
Financial Officer and Treasurer
December 16, 1996 /s/Paula H. Rushing
- ---------------------------- --------------------------------------------------------------
DATE Paula H. Rushing
Controller of Alagasco
December 16, 1996 /s/Stephen D. Ban
- ---------------------------- --------------------------------------------------------------
DATE Stephen D. Ban
Director
December 16, 1996 /s/James S. M. French
- ---------------------------- --------------------------------------------------------------
DATE James S. M. French
Director
December 16, 1996 /s/Wallace L. Luthy
- ---------------------------- --------------------------------------------------------------
DATE Wallace L. Luthy
Director
December 16, 1996 /s/Judy M. Merritt
- ---------------------------- --------------------------------------------------------------
DATE Judy M. Merritt
Director
</TABLE>
16
<PAGE> 17
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
ITEM 14(A)
<TABLE>
<CAPTION>
Reference Page
--------------
1996
1996 Annual
10-K Report
---- ------
<S> <C> <C>
1. Energen Corporation
-------------------
A. Financial Statements
Report of Independent Certified Public Accountants . . . . . . . . . 52
Consolidated statements of income for the years ended
September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . 31
Consolidated balance sheets as of September 30,
1996 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Consolidated statements of shareholders' equity for the years
ended September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . 34
Consolidated statements of cash flows for the years ended
September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . 35
Notes to consolidated financial statements . . . . . . . . . . . . . 36
B. Financial Statement Schedule
Report of Independent Certified Public Accountants . . . . . . . . . 37
Schedule II Valuation and Qualifying Accountants . . . . . . . . 38
2. Alabama Gas Corporation
-----------------------
A. Financial Statements
Report of Independent Certified Public Accountants . . . . . . . . . 22
Statements of income for the years ended
September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . 23
Balance sheets as of September 30, 1996 and 1995 . . . . . . . . . . 24
</TABLE>
17
<PAGE> 18
<TABLE>
<CAPTION>
Reference Page
--------------
1996
1996 Annual
10-K Report
---- ------
<S> <C> <C> <C>
Statements of shareholder's equity for the years ended
September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . 26
Statements of cash flows for the years ended
September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . 27
Notes to financial statements . . . . . . . . . . . . . . . . . . . 28
B. Financial Statement Schedule
Schedule II Valuation and Qualifying Accounts . . . . . . . . . 39
</TABLE>
Schedules other than those listed above are omitted for the reason that they
are not required or are not applicable, or the required information is shown in
the financial statements or notes thereto.
18
<PAGE> 19
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO EXHIBITS
ITEM 14(A)(3)
Exhibit
Number Description
- ------- -----------
*3(a) Restated Certificate of Incorporation of Energen Corporation
(formerly Alagasco, Inc.) which was filed as Exhibit 4(a) to
Energen's Registration Statement on Form S-8 (Registration No.
33-14855).
*3(b) Amendment to the Restated Certificate of Incorporation of Energen
Corporation (formerly Alagasco, Inc.) adopted on July 18, 1985,
which was filed as Exhibit 4(b) to Energen's Registration
Statement on Form S-8 (Registration No. 33-14855).
*3(c) Amendment to the Restated Certificate of Incorporation of Energen
Corporation adopted on January 15, 1987, which was filed as
Exhibit 4(c) to Energen's Registration Statement on Form S-8
(Registration No. 33-14855).
*3(d) Amendment to the Restated Certificate of Incorporation of Energen
Corporation adopted on January 25, 1989, which was filed as
Exhibit 4(d) to Energen's Registration Statement on Form S-3
(Registration No. 33-70464).
*3(e) Articles of Amendment to the Restated Certificate of
Incorporation of Energen Corporation dated February 3, 1995,
which was filed as Exhibit 3(e) to the Registrant's Annual Report
on Form 10-K for the year ended September 30, 1995, (file No.
1-7810).
*3(f) Restated Conformed Certificate of Incorporation of Energen
Corporation, as amended through February 3, 1995, which was filed
as Exhibit 3(f) to the Registrant's Annual Report on Form 10-K
for the year ended September 30, 1995, (file No. 1-7810).
*3(g) Certificate of Adoption of Resolutions designating Series A
Junior Participating Preferred Stock (June 27, 1988) which was
filed as Exhibit 4(e) to Energen's Registration Statement on Form
S-2 (Registration No. 33-25435).
*3(h) Bylaws of Energen Corporation, which were filed as Exhibit 4(e)
to Energen's Registration Statement on Form S-8 (Registration No.
33-14855).
*3(i) Articles of Amendment and Restatement of the Articles of
Incorporation of Alabama Gas Corporation, dated September 27,
1995, which was filed as Exhibit 3(i) to the Registrant's Annual
Report on Form 10-K for the year ended September 30, 1995, (file
No. 1-7810).
*3(j) By-Laws of Alabama Gas Corporation, which was filed as Exhibit
4(k) to Alabama Gas' Registration Statement on Form S-3
(Registration No. 33-12841).
*4(a) Rights Agreement, dated as of July 27, 1988, between Energen
Corporation and AmSouth Bank, N.A., Rights Agent, which was filed
as Exhibit 1 to Energen's Registration Statement on Form 8-A
(File No. 1-7810).
*4(b) Amendment of Rights Agreement, dated as of February 28, 1990,
between Energen Corporation and AmSouth Bank, N.A., Rights Agent,
which was filed as Exhibit 2 to Energen's Form 8 Amendment No. 2
to its Registration Statement on Form 8-A (File No. 1-7810).
19
<PAGE> 20
*4(c) Indenture, dated as of January 1, 1992, between Energen
Corporation and Boatmen's Trust Company, Trustee, which was filed
as Exhibit 4 to Energen's Amendment No. 1 to Registration
Statement on Form S-3 (Registration No. 33-44936).
*4(d) Indenture, dated as of March 1, 1993, between Energen Corporation
and Boatmen's Trust Company, Trustee, which was filed as Exhibit
4 to Energen's Registration Statement on Form S-3 (Registration
No. 33-25435).
*4(e) Form of Indenture between Energen Corporation and The Bank of New
York, as Trustee, which was dated as of September 1, 1996, and
which was filed as Exhibit 4(i) to the Registrant's Registration
Statement on Form S-3 (Registration No. 333-11239).
*4(f) Indenture dated as of November 1, 1993, between Alabama Gas
Corporation and NationsBank of Georgia, National Association,
Trustee, which was filed as Exhibit 4(k) to Alabama Gas's
Registration Statement on Form S-3 (Registration No. 3370466).
*10(a) Form of Service Agreement Under Rate Schedule CSS (No. S10710),
between Southern Natural Gas Company and Alabama Gas Corporation
as filed as Exhibit 10(a) to Energen's Annual Report on Form 10-K
for the year ended September 30, 1993.
*10(b) Form of Service Agreement Under Rate Schedule IT (No. 790420),
between Southern Natural Gas Company and Alabama Gas Corporation
as filed as Exhibit 10(b) to Energen's Annual Report on Form 10-K
for the year ended September 30, 1993.
*10(c) Form of Service Agreement Under Rate Schedule FT-NN (No. 866941),
between Southern Natural Gas Company and Alabama Gas Corporation
as filed as Exhibit 10(c) to Energen's Annual Report on Form 10-K
for the year ended September 30, 1993.
*10(d) Form of Service Agreement Under Rate Schedule FT (No. 866940)
between Southern Natural Gas Company and Alabama Gas Corporation
as filed as Exhibit 10(d) to Energen's Annual Report on Form 10-K
for the year ended September 30, 1993.
10(e) Form of Executive Retirement Supplement Agreement between Energen
Corporation and certain executive officers.
*10(f) Restricted Stock Incentive Plan of Energen Corporation, which was
filed as Exhibit 4 to Post Effective Amendment No. 2 to Energen
Corporation's Registration Statement on Forms S-8 and S-3
(Registration No. 2-89855).
10(g) Form of Severance Compensation Agreement between Energen
Corporation and certain executive officers.
*10(h) Energen Corporation 1988 Stock Option Plan as filed as Exhibit
10(i) to Energen's Annual Report on Form 10-K for the year ended
September 30, 1993.
*10(i) Energen Corporation 1992 Long-Range Performance Share Plan, dated
as of October 1, 1991, which was filed as Exhibit A to the
Registrant's Proxy Statement for its January 22, 1992, Annual
Meeting (File No. 1-7810).
*10(j) Amendment to Energen Corporation 1992 Long-Range Performance
Share Plan, which was filed as Appendix B to the Registrant's
Proxy Statement for its January 22, 1997, Annual Meeting (File
No. 1-7810).
20
<PAGE> 21
*10(k) Energen Corporation 1992 Directors Stock Plan, effective as of
January 22, 1992, which was filed as Exhibit B to Energen's Proxy
Statement for its January 22, 1992, Annual Meeting (File No.
1-7810).
*10(l) Amendment to Energen Corporation 1992 Directors Stock Plan, which
was filed as Appendix B to Energen's Proxy Statement for its
January 24, 1996, Annual Meeting (File No. 1-7810).
*10(m) Energen Corporation Director Fees Deferral Plan as filed as
Exhibit 10(l) to Energen's Annual Report on Form 10-K for the
year ended September 30, 1993.
*10(n) Energen Corporation Annual Incentive Compensation Plan, Revised
5/90, as amended effective October 1, 1993, as filed as Exhibit
10(m) to Energen's Annual report on Form 10-K for the year ended
September 30, 1994.
13 Information incorporated by reference from pages 23-57 of the
Energen Corporation 1996 Annual Report to Stockholders
21 Subsidiaries of Energen Corporation
23 Consent of Independent Certified Public Accountants (Energen
Corporation)
27.1 Financial Data Schedule of Energen Corporation (for SEC purposes
only)
27.2 Financial Data Schedule of Alabama Gas Corporation (for SEC
purposes only)
*Incorporated by reference
21
<PAGE> 22
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS OF ALABAMA GAS CORPORATION:
We have audited the financial statements and the financial statement schedule
of Alabama Gas Corporation listed in the index on pages 17 and 18 of this Form
10-K. These financial statements and the financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Alabama Gas Corporation as of
September 30, 1996 and 1995, and the results of its operations and its cash
flows for each of the three years in the period ended September 30, 1996, in
conformity with generally accepted accounting principles. In addition, in our
opinion, the financial statement schedule referred to above, when considered in
relation to the basic financial statements taken as a whole, presents fairly,
in all material respects, the information required to be included therein.
Coopers & Lybrand L.L.P.
Birmingham, Alabama
October 23, 1996
22
<PAGE> 23
STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
===========================================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
===========================================================================================================
<S> <C> <C> <C>
OPERATING REVENUES $ 357,252 $ 295,967 $ 344,637
- -----------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas 181,400 133,556 188,592
Operations 81,585 78,139 72,639
Maintenance 10,956 9,727 9,147
Depreciation 21,269 19,370 17,941
Income taxes
Current 8,699 8,392 10,623
Deferred, net 835 177 (2,418)
Deferred investment tax credits, net (487) (487) (487)
Taxes, other than income taxes 26,772 22,662 26,301
- -----------------------------------------------------------------------------------------------------------
Total operating expenses 331,029 271,536 322,338
- -----------------------------------------------------------------------------------------------------------
OPERATING INCOME 26,223 24,431 22,299
- -----------------------------------------------------------------------------------------------------------
OTHER INCOME
Allowance for funds used during construction 972 1,054 465
Other, net (649) (112) 452
- -----------------------------------------------------------------------------------------------------------
Total other income 323 942 917
- -----------------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt 7,390 7,730 6,475
Other interest expense 2,195 1,922 1,845
- -----------------------------------------------------------------------------------------------------------
Total interest charges 9,585 9,652 8,320
- -----------------------------------------------------------------------------------------------------------
NET INCOME AVAILABLE FOR COMMON $ 16,961 $ 15,721 $ 14,896
===========================================================================================================
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
23
<PAGE> 24
BALANCE SHEETS
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
===========================================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995
===========================================================================================================
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant $ 544,643 $ 504,371
Less accumulated depreciation 268,110 247,926
- -----------------------------------------------------------------------------------------------------------
Utility plant, net 276,533 256,445
- -----------------------------------------------------------------------------------------------------------
Other property, net 394 193
- -----------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash 803 727
Accounts receivable
Gas 26,999 22,215
Merchandise 1,730 1,546
Other 2,955 1,399
Affiliated companies 10,582 199
Allowance for doubtful accounts (2,985) (2,000)
Inventories, at average cost
Storage gas inventory 28,214 20,276
Materials and supplies 5,828 5,860
Liquified natural gas in storage 2,417 3,539
Deferred gas costs 1,975 1,426
Regulatory asset 2,246 6,321
Deferred income taxes 6,344 7,416
Prepayments and other 2,904 2,302
- -----------------------------------------------------------------------------------------------------------
Total current assets 90,012 71,226
- -----------------------------------------------------------------------------------------------------------
DEFERRED CHARGES AND OTHER ASSETS 7,467 7,403
- -----------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 374,406 $ 335,267
===========================================================================================================
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
24
<PAGE> 25
BALANCE SHEETS
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
===========================================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995
===========================================================================================================
<S> <C> <C>
CAPITAL AND LIABILITIES
CAPITALIZATION
Common shareholder's equity
Common stock, $0.01 par value; 3,000,000 shares authorized,
1,972,052 shares outstanding in 1996 and 1995 $ 20 $ 20
Premium on capital stock 31,682 31,682
Capital surplus 2,802 2,802
Retained earnings 95,044 87,638
- -----------------------------------------------------------------------------------------------------------
Total common shareholder's equity 129,548 122,142
Cumulative preferred stock, $0.01 par value, 120,000 shares
authorized -- --
Long-term debt 125,000 100,000
- -----------------------------------------------------------------------------------------------------------
Total capitalization 254,548 222,142
- -----------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Long-term debt due within one year -- --
Notes payable to banks -- --
Accounts payable
Trade 23,758 26,160
Affiliated companies 1,512 --
Accrued taxes 18,067 10,236
Customers' deposits 17,364 18,218
Supplier refunds due customers 17,257 3,315
Other amounts due customers 489 13,231
Accrued wages and benefits 4,459 5,228
Other 10,611 9,444
- -----------------------------------------------------------------------------------------------------------
Total current liabilities 93,517 85,832
- -----------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 16,883 16,343
Accumulated deferred investment tax credits 3,617 4,103
Regulatory liability 5,038 6,001
Customer advances for construction and other 803 846
- -----------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 26,341 27,293
- -----------------------------------------------------------------------------------------------------------
TOTAL CAPITAL AND LIABILITIES $ 374,406 $ 335,267
===========================================================================================================
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
25
<PAGE> 26
STATEMENTS OF SHAREHOLDER'S EQUITY
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
============================================================================================================
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
============================================================================================================
COMMON STOCK
----------------
NUMBER OF PAR PREMIUM ON CAPITAL RETAINED
SHARES VALUE CAPITAL STOCK SURPLUS EARNINGS
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
BALANCE AT SEPTEMBER 30, 1993 1,972,052 $ 20 $21,682 $ 2,802 $ 74,886
Net income 14,896
Cash dividends (8,695)
Capital contribution from parent 10,000
- ------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1994 1,972,052 20 31,682 2,802 81,087
Net income 15,721
Cash dividends (9,170)
- ------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1995 1,972,052 20 31,682 2,802 87,638
Net income 16,961
Cash dividends (9,555)
- ------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1996 1,972,052 $ 20 $ 31,682 $ 2,802 $ 95,044
============================================================================================================
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
26
<PAGE> 27
STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
===========================================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
===========================================================================================================
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net Income $ 16,961 $ 15,721 $ 14,896
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 21,269 19,370 17,941
Deferred income taxes, net 835 177 (2,418)
Deferred investment tax credits (487) (487) (487)
Net change in:
Accounts receivable (5,539) (113) 896
Inventories (6,784) 3,725 (23,913)
Deferred gas costs (549) 34 1,505
Accounts payable -- gas purchase (1,614) 9,882 1,220
Accounts payable -- other trade (788) (2,856) (2,110)
Other current assets and liabilities 12,048 (3,057) 15,763
Other, net (1,019) 673 (2,116)
- ------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 34,333 43,069 21,177
- ------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property, plant and equipment (42,037) (41,560) (37,853)
Net advances (to) from parent company (8,871) (199) 87
Other, net 1,377 (15) 181
- ------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (49,531) (41,774) (37,585)
- ------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Payment of dividends on common stock (9,555) (9,170) (8,695)
Reduction of long-term debt and preferred stock -- (37,214) (9,891)
Proceeds from medium term notes 24,829 49,660 49,670
Proceeds from capital contribution from parent -- -- 10,000
Net change in short-term debt -- (4,000) (25,000)
- ------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 15,274 (724) 16,084
- ------------------------------------------------------------------------------------------------------------
Net change in cash and cash equivalents 76 571 (324)
Cash and cash equivalents at beginning of period 727 156 480
- ------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 803 $ 727 $ 156
============================================================================================================
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
27
<PAGE> 28
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- --------------------------------------------------------------------------------
Alabama Gas Corporation (Alagasco), a wholly-owned subsidiary of Energen
Corporation, is the largest natural gas distribution utility in the State of
Alabama, serving customers primarily in central and north Alabama. The
following is a description of its significant accounting policies and
practices.
A. UTILITY PLANT AND DEPRECIATION: Property, plant and equipment is stated at
cost. The cost of utility plant includes an allowance for funds used during
construction. Maintenance is charged for the cost of normal repairs and the
renewal or replacement of an item of property which is less than a
retirement unit. When property which represents a retirement unit is
replaced or removed, the cost of such property is credited to utility plant
and, together with the cost of removal less salvage, is charged to the
accumulated reserve for depreciation. Depreciation is provided on the
straight-line method over the estimated useful lives of utility property at
rates established by the Alabama Public Service Commission (APSC). Approved
depreciation rates averaged approximately 4.3 percent in 1996, 1995 and
1994. The excess of total acquisition costs over book value of net assets
acquired to date is included in utility plant ($23.2 million, net of $6.5 in
accumulated amortization at September 30, 1996) and is being amortized on a
straight-line basis over approximately 23 years.
B. INVENTORIES: Inventories, which consist primarily of gas stored
underground, are stated at average cost.
C. OPERATING REVENUE AND GAS COSTS: In accordance with industry practice,
Alagasco records natural gas distribution revenues on a monthly- and
cycle-billing basis. The commodity cost of purchased gas applicable to gas
delivered to customers but not yet billed under the cycle-billing method is
deferred as a current asset.
D. REGULATORY ACCOUNTING: Alagasco is subject to the provisions of Statement
of Financial Accounting Standard (SFAS) No. 71, Accounting for the Effects
of Certain Types of Regulation. In general, SFAS No. 71 allows utilities to
capitalize or defer certain costs or revenues, based upon orders received
from regulatory authorities, to be recovered from or refunded to customers
in future periods.
E. INCOME TAXES: Alagasco files a consolidated income tax return with its
parent. The consolidated income taxes are allocated to the appropriate
subsidiaries using the separate return method. Deferred income taxes reflect
the impact of temporary differences between the tax basis of assets and
liabilities and their carrying amounts for financial reporting purposes and
are measured in compliance with enacted tax laws. Investment tax credits
have been deferred and are being amortized over the lives of the related
assets.
F. CASH EQUIVALENTS: Alagasco includes highly liquid marketable securities and
debt instruments purchased with a maturity of three months or less in cash
equivalents.
G. ESTIMATES: The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities at the date of the financial statements and the reported amount
of revenues and expenses during the reporting period. Actual results could
differ from those estimates.
2. REGULATORY MATTERS
- --------------------------------------------------------------------------------
As an Alabama utility, Alagasco is subject to regulation by the APSC which, in
1983, established the Rate Stabilization and Equalization (RSE) rate-setting
process. RSE was extended for the fourth time on October 7, 1996, for a
five-year period through January 1, 2002. Under the terms of that extension,
RSE will continue after January 1, 2002, unless, after notice to the Company
and a hearing, the Commission votes to either modify or discontinue its
operation.
Under RSE as extended, the APSC conducts quarterly reviews to determine, based
on Alagasco's projections and fiscal year-to-date performance, whether
Alagasco's return on equity for the fiscal year will be within the allowed
range of
28
<PAGE> 29
13.15 percent to 13.65 percent. Reductions in rates can be made quarterly to
bring the projected return within the allowed range; increases, however, are
allowed only once each fiscal 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. If the change in O&M expense per customer falls
within 1.25 percentage points above or below the Consumer Price Index For All
Urban Customers (index range), no adjustment is required. If, however, the
change in O&M expense per customer exceeds the index range, three-quarters of
the difference 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. Under RSE as extended, an $8.2 million annual increase
in revenue became effective December 1, 1995, and a $1.3 million decrease in
revenue became effective October 1, 1996.
Effective December 15, 1990, the APSC approved a temperature adjustment to
customers' monthly bills to remove the effect of departures from normal
temperature on Alagasco's earnings. The calculation is performed monthly, and
the adjustments to customers' bills are made in the same billing cycle the
weather variation occurs.
Alagasco's rate schedules for natural gas distribution charges contain a Gas
Supply Adjustment (GSA) rider, established in 1993, which permits the
pass-through to customers of changes in the cost of gas supply, including Gas
Supply Realignment (GSR) surcharges imposed by Alagasco's suppliers resulting
from changes in gas supply purchases related to the implementation of Federal
Energy Regulatory Commission (FERC) Order 636. On October 7, 1996, the APSC
issued an order providing for the refund to customers of approximately $17.1
million, including interest, of supplier refunds. The Order provides that
refunds shall be returned to customers prior to January 31, 1997. These refunds
were collected from a variety of sources and most relate to the settlement of
rate case and FERC Order 636 proceedings of Southern Natural Gas Company
(Southern) as described herein.
On September 9, 1996, the APSC approved Alagasco's application to issue $25
million of debt, a portion of which will be used to fund the supplier refunds
discussed above. On June 12, 1995, Alagasco received approval from the APSC to
issue $50 million of debt, a portion of which was used to redeem all of
Alagasco's 9 percent debentures and 11 percent First Mortgage Bonds. In
connection with the early call of the redeemed debt, Alagasco paid an early
call premium of approximately $1.3 million. Because the APSC authorized
Alagasco to collect the early call premium through customer rates, a regulatory
asset of $1.3 million was recorded at September 30, 1995, and the amounts were
collected during fiscal 1996.
In accordance with APSC-directed regulatory accounting procedures, Alagasco in
1989 began returning to customers excess utility deferred taxes which resulted
from a reduction in the federal statutory tax rate from 46 percent to 34
percent using the average rate assumption method. This method provides for the
return to ratepayers of excess deferred taxes over the lives of the related
assets. In 1993 those excess taxes were reduced as a result of a federal tax
rate increase from 34 percent to 35 percent. Remaining excess utility deferred
taxes of $2.7 million are being returned to ratepayers over approximately 14
years. At September 30, 1996 and 1995, regulatory liabilities of $5 million and
$6 million, respectively, were included in the financial statements related to
income taxes.
FERC Regulation: On March 15, 1995, Southern filed a comprehensive settlement
with the FERC in the form of a Stipulation and Agreement (the Settlement) to
resolve all issues in Southern's six pending rate cases, as well as to resolve
all GSR and transition cost issues resulting from the implementation of FERC
Order 636. Alagasco was a supporting party to the Settlement. On April 11,
1996, the FERC issued its Order on Rehearing approving the Settlement with
minor modifications. The Settlement, as approved by FERC, provides for the
following: (1) the resolution of all cost of service and rate design issues in
Southern's six pending rate cases and the establishment of reduced rates for
the purpose of calculating rate case refunds; (2) the implementation of reduced
settlement rates for supporting parties commencing March 1, 1995; (3) the
resolution of all GSR and other transition cost issues resulting from FERC
Order 636; (4) lower GSR cost recovery through the reduction and earlier payout
of GSR costs; (5) a three-year moratorium on general rate increases; and (6)
the resolution and disposition of all rate case and GSR refunds for supporting
parties. With respect to this last point, the Settlement provides that all
rate case refunds will be used to offset a portion of Southern's remaining GSR
liability. In addition, as a result of the recalculated GSR surcharges for the
period January 1, 1994, to February 28, 1995, Southern refunded over-collected
GSR costs. As a
29
<PAGE> 30
result of this FERC order, Alagasco received other refunds based on contracts
with other suppliers whose prices were tied to Southern's rates. In total,
$17.1 million will be refunded to customers prior to January 31, 1997, and
includes amounts received from Southern, other suppliers and accrued interest.
The Settlement, as approved by FERC, resolves all issues relating to GSR and
other transition costs with respect to supporting parties. Alagasco estimates
that it has a remaining GSR liability of approximately $0.8 million to be paid
through December 1997 and approximately $1.4 million in other transition costs
to be paid through June 1998. Because these costs will be recovered in full
from its customers, Alagasco recorded regulatory assets of $2.2 million and $5
million at September 30, 1996 and 1995, respectively.
<TABLE>
<CAPTION>
3. LONG-TERM DEBT AND NOTES PAYABLE
=========================================================================================================
Long-term debt consists of the following:
=========================================================================================================
As of September 30, (in thousands) 1996 1995
=========================================================================================================
<S> <C> <C>
Medium-term Notes, interest ranging from 5.4% to 7.97%, for notes
redeemable December 1, 1998, to September 23, 2026 $ 125,000 $ 100,000
Less amounts due within one year -- --
- ---------------------------------------------------------------------------------------------------------
Total $ 125,000 $ 100,000
=========================================================================================================
</TABLE>
In the prior year, Alagasco deposited $37.6 million into an irrevocable trust
to complete an in-substance defeasance of its 9 percent debentures and 11
percent Series H First Mortgage Bonds. The funds in the trust, primarily
obtained through the issuance of medium-term notes and short-term borrowings,
were used solely to satisfy the principal, interest, and call premium of the
defeased debt. Accordingly, the debt and related accrued interest were excluded
from the 1995 balance sheet. No gain or loss was recorded in the financial
statements as the APSC granted Alagasco regulatory relief related to the income
statement impact of this defeasance.
The aggregate maturities of long-term debt for the next five years are as
follows:
<TABLE>
<CAPTION>
=====================================================================================================
Years ending September 30, (in thousands)
=====================================================================================================
1997 1998 1999 2000 2001
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
$ -- $ -- $ 5,350 $ -- $ 4,650
=====================================================================================================
</TABLE>
Energen and Alagasco have short-term credit lines and other credit facilities
of $156 million available to either entity for working capital needs. The
following is a summary of information relating to notes payable to banks:
<TABLE>
<CAPTION>
=========================================================================================================
As of September 30, (in thousands) 1996 1995 1994
=========================================================================================================
<S> <C> <C> <C>
Alagasco outstanding $ -- $ -- $ 4,000
Other Energen outstanding 59,000 32,300 2,000
Available for borrowings 97,000 77,700 104,000
- ---------------------------------------------------------------------------------------------------------
Total $ 156,000 $ 110,000 $ 110,000
=========================================================================================================
Maximum amount outstanding at any month-end $ 22,000 $ 5,000 $ 60,000
Average daily amount outstanding $ 6,672 $ 447 $ 13,836
Weighted average interest rates based on:
Average daily amount outstanding 5.73% 5.69% 3.32%
Amount outstanding at year-end -- -- 5.17%
=========================================================================================================
</TABLE>
Total interest expense for Alagasco in 1996, 1995 and 1994 was $9,585,000,
$9,652,000, and $8,320,000, respectively.
30
<PAGE> 31
<TABLE>
<CAPTION>
4. INCOME TAXES
============================================================================================================
The components of income taxes consist of the following:
============================================================================================================
For the years ended September 30, (in thousands) 1996 1995 1994
============================================================================================================
<S> <C> <C> <C>
Taxes estimated to be payable currently:
Federal $ 7,924 $ 7,633 $ 9,664
State 775 759 959
============================================================================================================
Total current 8,699 8,392 10,623
============================================================================================================
Taxes deferred:
Federal 274 (326) (2,689)
State 74 16 (216)
============================================================================================================
Total deferred 348 (310) (2,905)
============================================================================================================
Total income tax expense $ 9,047 $ 8,082 $ 7,718
============================================================================================================
</TABLE>
Temporary differences and carryforwards which give rise to a significant
portion of deferred tax assets and liabilities for 1996 and 1995 are as
follows:
<TABLE>
<CAPTION>
============================================================================================================
As of September 30, (in thousands) 1996 1995
============================================================================================================
Current Noncurrent Current Noncurrent
========================== ==========================
<S> <C> <C> <C> <C>
Deferred tax assets:
Deferred investment tax credits $ -- $ 1,205 $ -- $ 1,386
Regulatory liabilities -- 1,872 -- 2,229
Unbilled revenue 1,658 -- 1,565 --
Insurance and accruals 2,239 -- 1,923 --
Gas supply adjustment -- -- 930 --
Accrued vacation 1,067 -- 988 --
Allowance for uncollectible accounts 1,268 -- 902 --
Other, net 2,300 74 2,022 52
- ------------------------------------------------------------------------------------------------------------
Subtotal 8,532 3,151 8,330 3,667
Valuation allowance -- -- -- --
- ------------------------------------------------------------------------------------------------------------
Total deferred tax assets $ 8,532 $ 3,151 $ 8,330 $ 3,667
============================================================================================================
Deferred tax liabilities:
Depreciation and basis differences $ -- $ 19,087 $ -- $ 19,297
Gas supply adjustment 500 -- -- --
Other, net 1,688 947 914 713
- ------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities $ 2,188 $ 20,034 $ 914 $ 20,010
============================================================================================================
</TABLE>
No valuation allowance with respect to deferred taxes is deemed necessary as
the Company anticipates generating adequate future taxable income to realize
the benefits of all deferred tax assets on the consolidated balance sheet.
31
<PAGE> 32
Total income tax expense differs from the amount which would be provided by
applying the statutory federal income tax rate to earnings before taxes as
illustrated below:
<TABLE>
<CAPTION>
=============================================================================================================
For the years ended September 30, (in thousands) 1996 1995 1994
=============================================================================================================
<S> <C> <C> <C>
Income tax expense at statutory federal income tax rate $ 9,103 $ 8,331 $ 7,915
Increase (decrease) resulting from:
Investment tax credits-deferred (487) (487) (487)
State income taxes, net of federal income tax benefit 559 512 486
Other, net (128) (274) (196)
- -------------------------------------------------------------------------------------------------------------
Total income tax expense $ 9,047 $ 8,082 $ 7,718
=============================================================================================================
</TABLE>
There were no tax-related balances due to affiliates at September 30, 1996 or
1995.
5. EMPLOYEE BENEFIT PLANS
================================================================================
All information presented concerning retirement income and other benefit plans
includes other affiliates of Energen Corporation as well as Alagasco.
The Company has two defined benefit non-contributory pension plans which cover
a majority of the employees. Benefits are based on years of service and final
earnings. The Company's policy is to use the "projected unit credit" actuarial
method for funding and financial reporting purposes. The expense for the plan
covering the majority of employees (Plan A) for the years ended September 30,
1996, 1995 and 1994, was $412,000, $1,158,000, and $15,000, respectively. The
expense for the second plan covering employees under certain labor union
agreements (Plan B) for 1996, 1995 and 1994 was $197,000, $339,000, and
$555,000, respectively.
The funded status of the plans is as follows:
<TABLE>
<CAPTION>
=========================================================================================================
As of June 30, (in thousands) Plan A Plan B
=========================================================================================================
1996 1995 1996 1995
===================== ========================
<S> <C> <C> <C> <C>
Vested benefits $(56,828) $(46,073) $ (14,210) $ (13,499)
Nonvested benefits (4,323) (5,912) (2,336) (2,083)
- ---------------------------------------------------------------------------------------------------------
Accumulated benefit obligation (61,151) (51,985) (16,546) (15,582)
Effects of salary progression (12,607) (11,047) -- --
- ---------------------------------------------------------------------------------------------------------
Projected benefit obligation (73,758) (63,032) (16,546) (15,582)
Fair value of plan assets, primarily equity and
fixed income securities 80,750 69,431 18,358 16,429
Unrecognized net gain (loss) (337) 1,470 (433) 296
Unrecognized prior service cost 35 41 1,205 1,412
Unrecognized net transition obligation (asset) (4,303) (5,111) 340 396
- ---------------------------------------------------------------------------------------------------------
Accrued pension asset $ 2,387 $ 2,799 $ 2,924 $ 2,951
=========================================================================================================
</TABLE>
At September 30, 1996, for both plans the discount rate used to measure the
projected benefit obligation was 7.75 percent, and the expected long-term rate
of return on plan assets was 8.25 percent. The annual rate of salary increase
for the salaried plan was 5.75 percent. At September 30, 1995, for both plans
the discount rate used to measure the projected benefit obligation was 7.5
percent, and the expected long-term rate of return on plan assets was 8.25
percent. The annual rate of salary increase for the salaried plan was 5.5
percent.
32
<PAGE> 33
The components of net pension costs for 1996, 1995 and 1994 were:
<TABLE>
<CAPTION>
=============================================================================================================
For the years ended September 30, (in thousands) Plan A Plan B
=============================================================================================================
1996 1995 1994 1996 1995 1994
============================ ===========================
<S> <C> <C> <C> <C> <C> <C>
Service Cost $ 2,147 $ 2,052 $ 1,873 $ 255 $ 224 $ 224
Interest cost on projected benefit obligation 4,617 4,728 4,550 1,166 1,095 1,042
Actual (return) on plan assets (22,733) (8,787) (504) (2,971) (2,172) (372)
Net amortization and deferral 16,381 2,106 (5,904) 1,747 1,192 (339)
Loss due to special termination benefits -- 1,489 -- -- -- --
Settlement gain -- (430) -- -- -- --
- -------------------------------------------------------------------------------------------------------------
Net pension expense $ 412 $ 1,158 $ 15 $ 197 $ 339 $ 555
=============================================================================================================
</TABLE>
In 1995 the Company recognized a loss for special termination benefits of
$1,489,000 and a settlement gain of $430,000 pursuant to a voluntary early
retirement option offered to all salaried, non-officer employees of at least 58
years of age with a minimum of 5 years' service. Of the 55 eligible employees,
41 accepted.
The Company has deferred compensation plan agreements for certain key
executives providing for payments on retirement, termination, death or
disability. The deferred compensation expense under these agreements for 1996,
1995 and 1994 was $1,002,000, $808,000, and $461,000, respectively. At June
30, 1996 and 1995, the accumulated post-retirement benefit obligation related
to these agreements was $6,206,000 and $4,770,000, the projected benefit
obligation was $9,442,000 and $5,904,000, and the accrued post-retirement
benefit liability was $464,000 and $199,000.
In addition to providing pension benefits, the Company provides certain
post-retirement health care and life insurance benefits. Substantially all of
the Company's employees may become eligible for such benefits if they reach
normal retirement age while working for the Company. In a prior year, the
Company adopted SFAS No.106, Employers' Accounting for Post-retirement benefits
Other Than Pensions, with respect to the accrual of such costs for salaried
employees. During fiscal year 1994, the Company adopted SFAS 106 with respect
to such costs for employees under collective bargaining agreements. There was
no cumulative effect on the income statement resulting from the adoption of FAS
106, as the Company elected to amortize transition costs over a 20-year period.
On December 6, 1993, the APSC adopted an order which allows the Company to
recover all costs accrued under SFAS 106 through rates.
While the Company has not adopted a formal funding policy, all of its accrued
post-retirement liability was funded at year-end. The expense for salaried
employees for the years ended September 30, 1996, 1995, and 1994 was
$1,984,000, $2,271,000, and $2,319,000, respectively. The expense for union
employees was $4,076,000, $3,613,000, and $3,685,000 during 1996, 1995 and
1994, respectively. The "projected unit credit" actuarial method was used to
determine the normal cost and actuarial liability.
A reconciliation of the estimated status of the obligation is as follows:
<TABLE>
<CAPTION>
=========================================================================================================
As of June 30, (in thousands) Salaried Employees Union Employees
=========================================================================================================
1996 1995 1996 1995
====================== ========================
<S> <C> <C> <C> <C>
Retirees $ (10,344) $ (9,091) $ (14,982) $(13,030)
Active, fully-eligible (1,574) (3,306) (4,011) (3,776)
Other active (7,989) (8,360) (14,415) (12,794)
- ----------------------------------------------------------------------------------------------------------
Accumulated post-retirement benefit obligation (19,907) (20,757) (33,408) (29,600)
Fair value of plan assets, primarily equity and
fixed income securities 17,519 12,659 8,399 4,419
Unamortized amounts 1,210 7,550 20,887 24,237
- ----------------------------------------------------------------------------------------------------------
Accrued post-retirement benefit liability $ (1,178) $ (548) $ (4,122) $ (944)
==========================================================================================================
</TABLE>
33
<PAGE> 34
Net periodic post-retirement benefit cost for the years ended September 30,
1996, 1995, and 1994 included the following:
<TABLE>
<CAPTION>
=============================================================================================================
For the years ended September 30, (in thousands) Salaried Employees Union Employees
=============================================================================================================
1996 1995 1994 1996 1995 1994
============================ ===========================
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 516 $ 512 $ 450 $ 876 $ 807 $ 481
Interest cost on accumulated post-retirement
benefit obligation 1,679 1,696 1,726 2,195 1,793 1,920
Amortization of transition obligation 723 723 723 1,285 1,285 1,285
Amortization of actuarial gains and losses (277) -- -- -- -- --
Deferred asset (gain) loss 658 539 (453) 177 424 --
Actual (return) on plan assets (1,315) (1,199) (127) (457) (696) (1)
- -------------------------------------------------------------------------------------------------------------
Net periodic post-retirement benefit expense $ 1,984 $ 2,271 $ 2,319 $ 4,076 $ 3,613 $ 3,685
=============================================================================================================
</TABLE>
The weighted average discount rate used in determining the accumulated
post-retirement benefit obligation was 7.75 percent and 7.5 percent in 1996 and
1995, respectively. The expected long-term rate of return on assets is 8.25
percent for both years, and the tax rate on investment income is assumed to be
40 percent. The weighted average health care cost trend rate used in
determining the accumulated post-retirement benefit obligation was 8 percent in
1996 and 1995. That assumption has a significant effect on the amounts
reported. For example, with respect to salaried employees, increasing the
weighted average health care cost trend rate by 1 percent would increase the
accumulated post-retirement benefit obligation by 2.4 percent and the net
periodic post-retirement benefit cost by 2.2 percent. For union employees,
increasing the weighted average health care cost trend rate by 1 percent would
increase the accumulated post-retirement benefit obligation by 7.5 percent and
the net periodic post-retirement benefit cost by 7.2 percent. The assumed
health care cost trend rate of 8 percent is not currently expected to change.
For pay-related life insurance benefits, the salary scale averages 5 percent.
For both defined benefit plans and other post-retirement plans, certain
financial assumptions are used in determining the Company's projected benefit
obligation. These assumptions are examined periodically by the Company and any
required changes are reflected in the subsequent determination of projected
benefit obligations.
The Company has a long-term disability plan covering most salaried employees.
Expense for the years ended September 30, 1996, 1995, and 1994 was $370,000,
$155,000, and $150,000, respectively.
6. CAPITAL STOCK
================================================================================
Alagasco's authorized common stock consists of 3 million, $0.01 par value
common shares. At September 30, 1996 and 1995, 1,972,052 shares were issued and
outstanding. Alagasco is authorized to issue 120,000 shares of preferred stock
par value $0.01 per share, in one or more series. There are no shares
currently outstanding.
7. COMMITMENTS AND CONTINGENCIES
================================================================================
Contracts and Agreements: Alagasco has various firm gas supply and firm gas
transportation contracts which expire at various dates through the year 2008.
These contracts typically contain minimum demand charge obligations on the part
of Alagasco.
Alagasco has entered into an agreement with a financial institution whereby it
can sell on an ongoing basis, with recourse, certain installment receivables
related to its merchandising program up to a maximum of $20 million. During
1996, 1995 and 1994, Alagasco sold $8,831,000, $8,454,000 and $6,784,000,
respectively, of installment receivables. At September 30, 1996 and 1995, the
balance of these installment receivables was $16,964,000 and $15,618,000,
respectively. Receivables sold under this agreement are considered financial
instruments with off-balance sheet risk. Alagasco's exposure to credit loss in
the event of non-performance by customers is represented by the balance of
installment receivables.
34
<PAGE> 35
ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight former
manufactured gas plant sites, of which it still owns four, and five
manufactured gas distribution sites, of which it still owns one. A preliminary
investigation of the sites does not indicate the present need for remediation
activities. Management expects that, should remediation of any such sites be
required in the future, Alagasco's share, if any, of such costs will not
materially affect the results of operations or financial condition of Alagasco.
LEGAL MATTERS: Alagasco is from time to time, party to various pending or
threatened legal proceedings. Certain of these lawsuits include claims for
punitive damages in addition to other specified relief. Based upon information
presently available, and in light of available legal and other defenses,
contingent liabilities arising from threatened and pending litigation are not
considered material in relation to the financial position of Alagasco. It
should be noted, however, that Alagasco conducts business in Alabama and other
jurisdictions in which the magnitude and frequency of punitive damage awards
bearing little or no relation to culpability or actual damages continue to rise
making it increasingly difficult to predict litigation results. Various legal
proceedings arising in the normal course of business are currently in progress
and Alagasco has accrued a provision for estimated costs.
CONCENTRATION OF CREDIT RISK: Natural gas distribution operating revenues and
related accounts receivable are generated from state-regulated utility natural
gas sales and transportation to more than 460,000 residential, commercial and
industrial customers located in central and north Alabama. A change in economic
conditions may affect the ability of customers to meet their obligations;
however, Alagasco believes that its provision for possible losses on
uncollectible accounts receivable is adequate for its credit loss exposure.
LEASE OBLIGATIONS: Total payments related to leases included as operating
expense in the accompanying consolidated statements of income were $2,146,000,
$2,201,000, and $2,147,000 in 1996, 1995 and 1994, respectively. Minimum future
rental payments (in thousands) required after 1996 under leases with initial or
remaining noncancelable lease terms in excess of one year are as follows:
<TABLE>
<CAPTION>
===========================================================================================================
1997 1998 1999 2000 2001 2002 and thereafter
===========================================================================================================
<S> <C> <C> <C> <C> <C>
$ 1,950 $ 724 $ 286 $ 256 $ 80 $ 80
===========================================================================================================
</TABLE>
8. SUPPLEMENTAL CASH FLOW INFORMATION
================================================================================
Supplemental information concerning cash flow activities is as follows:
<TABLE>
<CAPTION>
===========================================================================================================
For the years ended September 30, (in thousands) 1996 1995 1994
===========================================================================================================
<S> <C> <C> <C>
Interest paid, net of amount capitalized $ 9,216 $ 11,166 $ 7,762
Income taxes paid $ 5,932 $ 10,920 $ 9,097
Noncash investing activities:
Capitalized depreciation $ 166 $ 166 $ 155
Allowance for funds used during construction $ 972 $ 1,054 $ 465
Noncash financing activities (debt issuance costs) $ 171 $ 340 $ 330
===========================================================================================================
</TABLE>
9. FINANCIAL INSTRUMENTS
================================================================================
The fair value of cash and cash equivalents and trade receivables (net of
allowance), approximates fair value due to the short maturity of the
instruments.
The fair value of fixed-rate long-term debt, including the current portion,
would be $121,567,000 at September 30, 1996. The fair value was based on the
market value of debt with similar maturities and with interest rates currently
trading in the marketplace.
35
<PAGE> 36
10. RECENT PRONOUNCEMENTS OF THE FASB
================================================================================
In June 1995, the Financial Accounting Standards Board (FASB) issued SFAS No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of. This statement requires that long-lived assets be
reviewed for impairment whenever events or changes in the circumstances
indicate that the carrying amount for an asset may not be recoverable. The
Company is required to adopt this Statement in its 1997 fiscal year, but, based
on known facts and circumstances, does not expect implementation to have a
material impact on the Company's financial statements.
In October 1995, SFAS No. 123, Accounting for Stock-Based Compensation, was
issued and also requires adoption by the Company in its fiscal year 1997. SFAS
No. 123 establishes a fair value-based method of accounting for employee stock
options but allows companies to continue to follow the accounting treatment
prescribed by APB Opinion 25 with proper disclosure. The Company has not yet
determined the method of accounting that it will follow for stock options but
does not expect that adoption of the requirements of SFAS No. 123 will have a
material impact on the Company's financial statements.
In June 1996, SFAS No. 125, Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities, was issued and provides accounting
and reporting standards for such transactions. The Statement requires adoption
by the Company in its fiscal year 1998. Implementation of SFAS No. 125 is not
expected to have a material impact on the Company's financial statements.
11. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)
================================================================================
The following data summarize quarterly operating results. The Company's
business is seasonal in character and strongly influenced by weather
conditions.
<TABLE>
<CAPTION>
==========================================================================================================
1996 Fiscal Quarters
First Second Third Fourth
==========================================================================================================
<S> <C> <C> <C> <C>
Operating revenues $ 73,185 $ 162,143 $ 77,225 $ 44,699
Operating income (loss) $ 4,124 $ 21,271 $ 3,638 $ (2,810)
Net income (loss) available for common $ 1,986 $ 18,646 $ 1,380 $ (5,051)
==========================================================================================================
</TABLE>
<TABLE>
<CAPTION>
1995 Fiscal Quarters
First Second Third Fourth
==========================================================================================================
<S> <C> <C> <C> <C>
Operating revenues $ 67,226 $ 134,141 $ 55,865 $ 38,735
Operating income (loss) $ 3,696 $ 19,276 $ 3,383 $ (1,924)
Net income (loss) available for common $ 1,751 $ 17,267 $ 1,772 $ (5,069)
==========================================================================================================
</TABLE>
12. TRANSACTIONS WITH RELATED PARTIES
================================================================================
Alagasco purchased natural gas from affiliates amounting to $5,097,000,
$4,644,000, and $10,255,000, in 1996, 1995, and 1994, respectively. These
amounts are included in gas purchased for resale. Alagasco had net receivables
from affiliates of $9,049,000 at September 30, 1996, and net payables to
affiliates of $183,000 at September 30, 1995.
36
<PAGE> 37
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS OF ENERGEN CORPORATION:
Our report on the consolidated financial statements of Energen Corporation and
subsidiaries has bene incorporated by reference in this Form 10-K from page 52
of the 1996 Annual Report to Stockholders of Energen Corporation and
subsidiaries. In connection with our audits of such financial statements, we
have also audited the related financial statement schedule listed in the index
on page 17 of this Form 10-K.
In our opinion, the financial statement schedule referred to above, when
considered in relation to the basic financial statements taken as a whole,
present fairly, in all material respects the information required to be
included therein.
Coopers & Lybrand L.L.P.
Birmingham, Alabama
October 23, 1996
37
<PAGE> 38
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
Energen Corporation and Subsidiaries
<TABLE>
<CAPTION>
====================================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
====================================================================================================
<S> <C> <C> <C>
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year $ 2,533 $ 2,037 $ 1,927
- ----------------------------------------------------------------------------------------------------
Additions:
Charged to income: 2,361 2,431 1,825
Recoveries and adjustments (187) 67 153
- ----------------------------------------------------------------------------------------------------
2,174 2,498 1,978
- ----------------------------------------------------------------------------------------------------
Less uncollectible accounts written off 1,705 2,002 1,868
- ----------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR $ 3,002 $ 2,533 $ 2,037
====================================================================================================
</TABLE>
38
<PAGE> 39
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
====================================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
====================================================================================================
<S> <C> <C> <C>
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year $ 2,000 $ 2,000 $ 1,800
- ----------------------------------------------------------------------------------------------------
Additions:
Charged to income: 2,349 1,935 1,805
Recoveries and adjustments (187) 67 263
- ----------------------------------------------------------------------------------------------------
2,162 2,002 2,068
- ----------------------------------------------------------------------------------------------------
Less uncollectible accounts written off 1,177 2,002 1,868
- ----------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR $ 2,985 $ 2,000 $ 2,000
====================================================================================================
</TABLE>
39
<PAGE> 1
EXHIBIT 10(e)
EXECUTIVE RETIREMENT SUPPLEMENT AGREEMENT
THIS EXECUTIVE RETIREMENT SUPPLEMENT AGREEMENT made effective
as of _________________________ between Energen Corporation, a corporation (the
"Company"), and ___________________________ (the "Executive").
R E C I T A L S
The Executive has been employed by the Company and/or one or
more of its subsidiaries for a number of years, and as an employee has provided
capable executive leadership and management so as to enable the Company to
operate efficiently and effectively. The Company and the Executive desire to
enter into this Agreement to provide for payment to the Executive and the
Executive's eligible spouse certain deferred compensation in the form of a
retirement supplement under certain circumstances.
NOW, THEREFORE, in consideration of the mutual promises of the
parties and the parties agree as follows:
ARTICLE 1 -- DEFINITIONS
1.1 Agreement: This document, including any attached schedules,
and any amendments to the same.
1.2 Birthday: An anniversary of the Executive's birth regardless
of whether the Executive survives to such anniversary.
1.3 Cause: Termination of employment by the Employer for "Cause"
shall mean TERMINATION based on any of the following:
(a) The willful and continued failure by the Executive to
substantially perform such Executive's duties with the Employer (other than any
such failure resulting from such Executive's incapacity due to physical or
mental illness) after a written demand for substantial performance is delivered
to the Executive specifically identifying the manner in which such Executive
has not substantially performed such Executive's duties;
(b) The engaging by the Executive in willful misconduct
which is demonstrably injurious to the Employer monetarily or otherwise; or
(c) The conviction of the Executive of a felony.
1.4 Code: The Internal Revenue Code of 1986, as the same may
from time to time be amended.
1
<PAGE> 2
1.5 Committee: The Officers Review Committee of the Board of
Directors of the Company or any person or persons appointed by the Board of
Directors to administer the Agreement.
1.6 Compensation: The sum of A plus B. For purposes of this
definition, A shall equal the average aggregate monthly basic pay from all
Employers for the 36 consecutive calendar months during which the Executive had
the highest average monthly basic pay out of the 60 calendar months immediately
preceding the Severance Date. For purposes of this definition, B shall equal C
divided by 12, where C equals the average of the Executive's three highest
annual cash incentive awards under the Energen Annual Incentive Compensation
Plan (or successor annual cash incentive plan) for the five Company fiscal
years immediately preceding the earlier of (i) the fiscal year during which the
Severance Date occurs or (ii) the fiscal year during which the Executive's 61st
birthday occurs.
1.7 Disability: Total and permanent disability which entitles the
Executive to a disability benefit under the disability program sponsored and/or
maintained by the Company or the Executive's Employer.
1.8 Eligibility Date: The earliest date on which the Executive
could be entitled to receive the Executive's "primary insurance amount" or any
portion thereof under the federal Social Security Act as amended and in effect
on the Severance Date assuming that the Executive survives to such date.
1.9 Employer: The Company and any and all subsidiaries of the
Company and their respective successors and assigns.
1.10 Lump Sum Election: An election made by the Executive pursuant
to Section 2.5 to receive a lump sum payment in lieu of the Supplemental
Retirement Benefit.
1.11 Normal Retirement Date: The first day of the month on or next
following the Executive's 60th Birthday; provided, however, if the Executive's
employment with an Employer continues beyond such date, the first day of the
month on or next following the date on which the Executive actually Retires
shall be Normal Retirement Date.
1.12 Present Value: The present value of a benefit or benefits
determined using the discount rate used to determine the present value of
payments under Section 280G of the Code that is in effect at the date payment
is to be made and the mortality assumptions utilized to determine actuarial
equivalent benefits under the Retirement Plan at that date.
1.13 Retire or Retirement: Termination of employment (for whatever
reason including death) from all Employers after attaining age 60.
1.14 Retirement Plan: The "Energen Corporation Retirement Income
Plan," as the same may be amended and in effect from time to time hereafter.
2
<PAGE> 3
1.15 Retirement Plan Benefit: The monthly amount of retirement
benefit payable to the Executive from the Retirement Plan in the normal form,
with no election of an optional form of payment, calculated under the terms of
the Retirement Plan as in effect on the Severance Date and with the following
assumptions: (i) the Executive will accrue no Years of Service or partial Years
of Service under the Retirement Plan after the Severance Date; (ii) the first
payment to the Executive under the Retirement Plan will be made on the first
day of the month on or next following the later of the Executive's 60th
Birthday or the Severance Date; and (iii) the Executive will live to the
payment date described in the preceding clause (ii).
1.16 Service: The number of the Executive's completed months of
continuous employment with the Employer ending on the Executive's Severance
Date.
1.17 Service Factor: If the Executive has 240 or more months of
Service then the Service Factor shall equal one (l). At any time prior to the
time when the Executive has both earned a vested benefit under the Retirement
Plan and been continuously employed by an Employer for five years, the Service
Factor shall be 0. Except as otherwise provided in the foregoing sentences,
the Service Factor shall be a fraction, the numerator of which shall be the
number of the Executive's months of Service and the denominator of which shall
be 240.
1.18 Severance Date: The earlier of (i) the first date on which
(for whatever reason) the Executive is no longer employed by an Employer, or
(ii) the date of termination of this Agreement pursuant to Article 3.
1.19 Social Security Benefit: The amount of the monthly benefit,
as estimated by the Committee in a consistent and uniform manner, which, under
the provisions of the federal Social Security Act as amended and in effect on
the Severance Date, such Executive is, or will be, entitled to receive as the
Executive's "primary insurance amount" or any portion thereof at the later of
the Eligibility Date or the Normal Retirement Date assuming (i) that the
Executive has or will make appropriate and timely application for such benefit,
(ii) that no event has occurred or will occur by reason of which the amount of
such benefit has been or will be delayed, suspended or forfeited in whole or in
part, (iii) that if the Severance Date occurs prior to the Executive's 60th
Birthday, the Executive will continue to receive, until the Executive's 60th
Birthday, earnings at the Compensation rate taxable as wages by the Social
Security Act, and (iv) that, after the later to occur of the Executive's 60th
birthday or Normal Retirement Date, the Executive will have no further earnings
taxable as wages by the Social Security Act.
1.20 Spouse: The spouse to whom the Executive was married at the
date of the Executive's death and throughout the twelve-month period preceding
the Executive's Severance Date.
1.21 Supplemental Retirement Benefit: The benefit described in
Section 2.2.
1.22 Supplemental Spouse's Retirement Benefit: The benefit
described in Section 2.3.
3
<PAGE> 4
1.23 The masculine gender shall be deemed to include the feminine;
the feminine to include the masculine; the singular to include the plural; and
the plural to include the singular in each case where appropriate.
ARTICLE 2 -- BENEFITS
2.1 Eligibility. The Executive and Spouse, as applicable, shall
be entitled to the benefits described in Sections 2.2 and 2.3; provided, that
no benefits shall be paid under this Agreement if (i) the Executive's
employment by an Employer is terminated for Cause, or (ii) the Severance Date
occurs for any reason before the Executive has both earned a vested benefit
under the Retirement Plan and been continuously employed by an Employer for
five years.
2.2 Supplemental Retirement Benefit. Subject to the other
provisions of this Agreement, commencing on the Executive's Normal Retirement
Date the Executive shall be entitled to receive a Supplemental Retirement
Benefit, which shall be payable monthly during the Executive's life with the
last payment being the payment made or due for the month in which the Executive
dies. No benefit shall be payable under this Section 2.2 if the Executive dies
on or before the Normal Retirement Date.
The Supplemental Retirement Benefit shall be an amount equal
to the product of "A" multiplied by the Service Factor. With respect to
Supplemental Retirement Benefit payments made for periods commencing prior to
the Eligibility Date, "A" shall equal the amount by which 60% of Compensation
exceeds the Retirement Plan Benefit. With respect to Supplemental Retirement
Benefit payments made for periods commencing on or after the Eligibility Date,
"A" shall equal the amount by which 60% of Compensation exceeds the sum of the
Retirement Plan Benefit plus the Social Security Benefit.
If the Executive terminates employment due to Disability, (i)
the period that the Executive receives disability benefits from a disability
program sponsored or maintained by an Employer shall be treated as Service, and
(ii) the Supplemental Retirement Benefit shall not commence, and the Executive
shall not be deemed to have had a Severance Date, while the Executive is
receiving disability benefits payable from a disability program sponsored or
maintained by an Employer. For purposes of this Section 2.2, reclassification
under the Retirement Plan from Disability Retirement to Retirement shall
constitute cessation of disability benefits.
2.3 Supplemental Spouse's Retirement Benefit.
(a) Subject to the other provisions of this Agreement,
following the Executive's death the surviving Spouse shall be entitled to a
Supplemental Spouse's Retirement Benefit, which shall be payable monthly
commencing on the later of (i) the first day of the month following the month
of the Executive's death or (ii) the first day of the month of the Executive's
55th Birthday, and continuing until the Spouse's death. The Supplemental
Spouse's Retirement Benefit shall be an amount equal to 50% of the monthly
Supplemental Retirement Benefit which the Executive would have been entitled to
receive had death not occurred (based on Service through the
4
<PAGE> 5
Severance Date and adjusting on the Eligibility Date); provided that if the
Executive's death occurs after the Severance Date, for each of the first three
months following the Executive's death the Supplemental Spouse's Retirement
Benefit shall be 100% of such amount.
(b) If the Executive shall die while a Lump Sum Election
is in effect and while the Executive is still employed by the Employer, the
surviving Spouse shall receive in lieu of the benefit described in Section
2.3(a) above, a lump sum payment equal to one-half of the Present Value of the
Supplemental Retirement Benefit which the Executive would have been entitled to
receive based on Service through the Severance Date if the Executive had
survived to the Normal Retirement Date. Such benefit shall be paid as promptly
as practicable after the Executive's death and, in all events, within
forty-five (45) days after the Executive's death. For purposes of this Section
2.3(b), the determination of whether a Spouse has survived the Executive shall
be made in accordance with the provisions of Section 43-8-43 of the Code of
Alabama of 1975, as the same may from time to time be amended (as of the date
of this Agreement, Section 43-8-43 generally treats a person as having
predeceased a decedent unless the person survives the decedent by five days).
(c) If the Executive shall die after the Severance Date,
while a Lump Sum Election is in effect, and prior to receipt of the lump sum
payment, the lump sum benefit shall be payable to the Executive's estate and no
Supplemental Spouse's Retirement Benefit shall be payable to the surviving
Spouse, if any.
(d) If the Executive dies after payment of a lump sum
pursuant to Section 2.5, no Supplemental Spouse's Retirement Benefit shall be
payable to the Executive's surviving Spouse, if any.
(e) No benefit shall be payable following the Executive's
death except as provided in this Section 2.3.
2.4 Spouse's Age. If a Spouse who is entitled to a benefit under
this Article 2 is more than ten (10) years younger than the Executive, any
benefit payable to the Spouse under Section 2.3(a) (but not 2.3(b)) shall be
reduced by 1/20 for each full year of age difference more than ten (10).
2.5 Payment Elections.
(a) By checking the appropriate box on the
signature page of this Agreement, the Executive may elect to receive, in lieu
of the Supplemental Retirement Benefit to which the Executive will otherwise
become entitled under Section 2.2 hereof, a lump sum payment that is the
Present Value, as of the date payment is made, of such Supplemental Retirement
Benefit. Such payment shall be made as promptly as practicable after the
Executive's Severance Date and, in all events, within forty-five (45) days
after such Severance Date.
(b) By executing and filing with the Company a
form substantially identical to Exhibit I hereof, or such other form as the
Company may prescribe or approve, the
5
<PAGE> 6
Executive may revoke an election made pursuant to paragraph (a) above or may
make any election which could be made pursuant to such paragraph, but any such
election or revocation of an election shall not become effective if the
Executive's Severance Date occurs within one year from the date such revocation
or election is made.
2.6 Leave of Absence. In the event the Executive is granted a
leave of absence, the Executive's employment shall be deemed to continue and
shall be treated as Service, during the period of such leave of absence unless
specifically determined to the contrary by the Committee.
ARTICLE 3 -- AMENDMENT OR TERMINATION OF AGREEMENT
3.1 Subject to Section 3.2 below, the Company reserves the right
to terminate this Agreement at any time by action of its Board of Directors or
the Committee, and the continuance of this Agreement is not guaranteed to the
Executive.
3.2 No termination of this Agreement shall operate to reduce,
cancel or void the Company's obligation to pay benefits provided for under this
Agreement and accrued prior to the Severance Date.
3.3 This Agreement may be amended by written instrument executed
by the Executive and by an officer of the Company thereunto duly authorized by
the Board of Directors of the Company.
ARTICLE 4 -- MISCELLANEOUS
4.1 This Agreement shall under no circumstances be deemed to have
any effect upon the terms or conditions of employment of the Executive. The
establishment and maintenance of this Agreement shall not be construed as
creating or modifying any contract between an Employer and the Executive nor is
it in lieu of any other benefits. This Agreement shall under no circumstances
be deemed to constitute a contract of insurance.
4.2 This Agreement shall not give the Executive the right to be
retained in the employ of an Employer or any right or interest hereunder other
than as specifically provided herein.
4.3 Benefits under this Agreement shall not be subject in any
manner to anticipation, alienation, sale, transfer, assignment, pledge or
encumbrance by the Executive or the Spouse and any attempt to so transfer or
encumber the benefits shall be null and void. Benefits under this Agreement
shall not be subject to or liable for the debts, contracts, liabilities,
engagements or torts of the Executive or of the Spouse nor may the same be
subject to attachment or seizure by any creditor of the Executive or the
Executive's spouse under any circumstances.
6
<PAGE> 7
4.4 In the event of the Executive's Retirement, Disability or
death, the Executive or the Executive's Spouse, as the case may be, should
notify the Committee promptly, and the Committee will then provide a Claimant's
statement form for completion which should be returned to the Committee
together with evidence of Disability or with an official death certificate, if
applicable. In the event that any claim hereunder is denied, the Committee
will provide adequate notice in writing to the Executive or Spouse, setting
forth the specific reasons for such denial and, in addition, the Committee will
afford a reasonable opportunity for a full and fair review of those reasons.
IN WITNESS WHEREOF, the Company has caused this Agreement to
be executed by its duly authorized officer and the Executive has hereunto set
his/her hand and seal all as of the day and year first above written.
ENERGEN CORPORATION
By:
------------------------------------
Its:
-----------------------------------
EXECUTIVE
----------------------------------------
ELECTION
[ ] I hereby elect to have my benefit paid as provided in Section
2.2 of this Agreement.
[ ] Pursuant to Section 2.5 of this Agreement, I hereby elect to
have my benefit paid in a lump sum.
7
<PAGE> 8
EXHIBIT I
ELECTION
PURSUANT TO
EXECUTIVE RETIREMENT SUPPLEMENT AGREEMENT
I hereby revoke any and all elections heretofore made by me
pursuant to the terms of that certain Executive Retirement Supplement Agreement
entered into by and between Energen Corporation and myself dated as of
________________, and elect to have my benefit
[ ] paid as provided in Section 2.2 of such Agreement.
[ ] paid in a lump sum pursuant to Section 2.5 of such
Agreement.
I understand that the foregoing election (and revocation, if
applicable), will not become effective if my Severance Date occurs within
one-year from the date of acceptance indicated below.
----------------------------------------
EXECUTIVE
----------------------------------------
Accepted by:
ENERGEN CORPORATION
----------------------------------------
By:
----------------------------------
Its:
----------------------------------
Date:
----------------------------------
8
<PAGE> 1
EXHIBIT 10(g)
SEVERANCE COMPENSATION AGREEMENT
THIS AGREEMENT ("Agreement") is made and entered into as of
the ____ day of _________, 199_, by and between ENERGEN CORPORATION, an Alabama
corporation ("Energen"), and _______________________________, ("Executive").
W I T N E S S E T H:
WHEREAS, Executive is an effective and valuable employee of
Energen and/or one or more of its subsidiaries;
WHEREAS, Executive desires certain assurances with respect to
any change in control of Energen;
WHEREAS, Energen recognizes that the uncertainties involved in
a potential or actual change in control of Energen could result in the
distraction or departure of management personnel such as Executive to the
detriment of Energen and its shareholders; and
WHEREAS, Energen desires to lessen the personal and economic
pressure which a potential or actual change in control may impose on Executive
and thereby facilitate Executive's ability to bargain successfully for the best
interests of Energen's shareholders in the event of such a change in control;
NOW, THEREFORE, in consideration of the premises and the
mutual agreements herein contained, Energen and Executive hereby agree as
follows:
Section 1. Definitions. As used in this Agreement
the following words and terms shall have the following meanings:
(a) "Applicable Period" means the period commencing with
the earliest date that a Change in Control occurs and ending on the last day of
the thirty-sixth calendar month following the calendar month during which such
Change in Control occurred. Anything in this Agreement to the contrary
notwithstanding, if a Change in Control occurs, and if the Date of Termination
with respect to Executive's employment with Energen occurs prior to the date on
which the Change in Control occurs, and if it is reasonably demonstrated by
Executive that such termination of employment (i) was at the request of a third
party who has taken steps reasonably calculated to effect the Change in Control
or (ii) otherwise arose in connection with or in anticipation of the Change in
Control, then for all purposes of this Agreement the "Applicable Period" shall
be deemed to have commenced on the date immediately preceding the Date of
Termination.
<PAGE> 2
(b) "Cause". Termination of employment by Employer for
"Cause" shall mean termination based on any of the following:
(1) The willful and continued failure by the
Executive to substantially perform Executive's duties with Employer (other than
any such failure resulting from Executive's incapacity due to physical or mental
illness) after a written demand for substantial performance is delivered to
Executive specifically identifying the manner in which Executive has not
substantially performed Executive's duties;
(2) The engaging by Executive in willful
misconduct which is demonstrably injurious to Employer monetarily or otherwise;
or
(3) The conviction of Executive of a felony.
(c) "Change in Control" means the occurrence of
any one or more of the following:
(1) The acquisition by any individual, entity or
group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act)
(a "Person") of beneficial ownership (within the meaning of Rule 13(d)-3
promulgated under the Exchange Act) of 25% or more of either (i) the then
outstanding shares of common stock of Energen (the "Outstanding Common Stock")
or (ii) the combined voting power of the then outstanding voting securities of
Energen entitled to vote generally in the election of directors (the
"Outstanding Voting Securities"); provided, however, that for purposes of this
subsection (1) any acquisition by an employee benefit plan (or related trust)
sponsored or maintained by Energen or any corporation controlled by Energen
shall not constitute a Change in Control;
(2) Individuals who, as of June 1, 1996,
constitute the Board of Directors of Energen (the "Incumbent Board") cease for
any reason to constitute at least a majority of the Board of Directors of
Energen (the "Board of Directors"); provided, however that any individual
becoming a director subsequent to the date hereof whose election, or nomination
for election by Energen's shareholders, was approved by a vote of at least a
majority of the directors then comprising the Incumbent Board shall be
considered as though such individual were a member of the Incumbent Board, but
excluding, for this purpose, any such individual whose initial assumption of
office occurs as a result of an actual or threatened election contest with
respect to the election or removal of directors or other actual or threatened
solicitation of proxies or consents by or on behalf of a Person other than the
Board of Directors;
(3) Consummation of a reorganization, merger or
consolidation involving, or sale or other disposition of all or substantially
all of the assets of, Energen (a "Business Combination"), in each case, unless,
following such Business Combination, (i) all or substantially all of the
individuals and entities who were the beneficial owners, respectively, of the
Outstanding Common Stock and Outstanding Voting Securities immediately prior to
such Business Combination beneficially own, directly or indirectly, more than
75% of, respectively, the then outstanding shares of common stock and the
combined voting power of the then
2
<PAGE> 3
outstanding voting securities entitled to vote generally in the election of
directors, as the case may be, of the corporation resulting from such Business
Combination (including, without limitation, a corporation which as a result of
such transaction owns Energen or all or substantially all of Energen's assets
either directly or through one or more subsidiaries) in substantially the same
proportions as their ownership, immediately prior to such Business Combination,
of the Outstanding Common Stock and Outstanding Voting Securities, as the case
may be, (ii) no Person (excluding any corporation resulting from such Business
Combination or any employee benefit plan (or related trust) of Energen or such
corporation resulting from such Business Combination) beneficially owns,
directly or indirectly, 25% or more of, respectively, the then outstanding
shares of common stock of the corporation resulting from such Business
Combination or the combined voting power of the then outstanding voting
securities of such corporation except to the extent that such ownership existed
prior to the Business Combination and (iii) at least a majority of the members
of the board of directors of the corporation resulting from such Business
Combination were members of the Incumbent Board at the time of the execution of
the initial agreement, or of the action of the Board of Directors, providing
for such Business Combination;
(4) The occurrence of one transaction or a series
of transactions, which has the effect of a divestiture by Energen of 25% or
more of the combined voting power of Alabama Gas Corporation's outstanding
voting securities;
(5) The occurrence of any sale, lease or other
transfer, in one transaction or a series of transactions of all or
substantially all of the assets of Alabama Gas Corporation (other than to
Energen or an entity controlled by Energen); or
(6) Any transaction or series of transactions
which is expressly designated by resolution of the Board of Directors to
constitute a Change in Control for purposes of this Agreement.
(d) "Code" means the Internal Revenue Code of 1986, as
the same may be from time to time amended.
(e) "Compensation" means an amount equal to the sum of
(A) plus (B), where (A) is the Executive's annualized base salary in effect at
the time of a Change in Control, and (B) is the highest annual bonus awarded
Executive by Employer pursuant to the Energen Annual Incentive Compensation
Plan (or any successor annual cash incentive plan) with respect to the three
(3) fiscal years immediately preceding the fiscal year in which the Change in
Control occurs.
(f) "Date of Termination" means the date that a
termination of Executive's employment with Employer is first effective.
(g) "Disability" means the total and permanent disability
which entitles Executive to a disability benefit under a disability program
sponsored and/or maintained by Energen.
(h) "Employer" means Energen and its Subsidiaries.
3
<PAGE> 4
(i) "Excess Parachute Payment" shall have the same
meaning as the term "excess parachute payment" defined in Section 280G(b)(1) of
the Code.
(j) "Exchange Act" means the Securities Exchange Act of
1934, as amended.
(k) "Good Reason" means the occurrence during an
Applicable Period of any of the following events without Executive's prior
written consent:
(1) The assignment to Executive by Employer of
duties inconsistent with Executive's position, authority, duties,
responsibilities and status with Employer immediately prior to a Change in
Control, or a change in Executive's titles or offices as in effect immediately
prior to a Change in Control, or any removal of Executive from or any failure
to reelect Executive to any of such positions, if such assignment, change, or
removal results in a diminution in Executive's position, authority, duties,
responsibilities or status with Employer immediately prior to a Change in
Control or any other action by Employer that results in such a diminution in
Executive's position, authority, duties, responsibilities or status;
(2) A reduction in Executive's aggregate rate of
monthly base pay from the Employer;
(3) The termination or material adverse
modification of the Energen Annual Incentive Compensation Plan or the Energen
Corporation 1996 Long-Range Performance Share Plan (or any other short or
long-term incentive compensation plan in effect immediately prior to a Change
in Control) without substitution of new short or long-term incentives providing
comparable compensation opportunities for Executive.
(4) A failure by Employer to use its best efforts
to provide Executive with either the same fringe benefits (including retirement
benefits and paid vacations) as were provided to Executive immediately prior to
a Change in Control or a package of fringe benefits that, though one or more of
such benefits may vary from those in effect immediately prior to the Change in
Control, is substantially comparable in all material respects to the fringe
benefits (taken as a whole) in effect prior to a Change in Control;
(5) Executive's relocation by Employer to any
place more than 25 miles from the location at which Executive performed the
substantial portion of Executive's duties prior to a Change in Control, except
for required travel by Executive on Employer's business to an extent
substantially consistent with Executive's business travel obligations
immediately prior to such Change in Control;
(6) Any material breach by Energen of any
provision of this Agreement or any other agreement between Energen and
Executive which breach continues for a period of thirty days following delivery
by Executive to Energen of written notice of such breach.
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<PAGE> 5
(l) "Independent Auditor" means the firm of certified
public accountants which at the time of the Change in Control had been most
recently engaged by Energen to prepare Energen's audited financial statements,
or any other firm of certified public accountants mutually agreeable to Energen
and Executive.
(m) "Notice of Termination" has the meaning set forth in
Section 2(a) of this Agreement.
(n) ""Parachute Payment" shall have the same meaning as
the term "parachute payment" defined in Section 280G(b)(2) of the Code.
(o) "Qualified Termination" shall mean
(1) during a Window Period, any termination
(including Retirement) of Executive's employment, other than for Cause, death
or Disability, and
(2) during the Applicable Period but not during a
Window Period,
(i) any termination by Employer of
Executive's employment other than for Cause,
(ii) a termination of Executive's
employment which Executive and Energen agree in writing will constitute a
Qualified Termination for purposes of this Agreement, and
(iii) a voluntary termination of
Executive's employment by Executive for Good Reason.
(p) "Reasonable Compensation" shall have the same meaning
as provided for the term "reasonable compensation" in Section 280G(b)(4) of the
Code.
(q) "Retirement" means termination of Executive's
employment (other than for Good Reason) by the Executive on or after
Executive's having reached age 60.
(r) "Subsidiary" means any corporation, the majority of
the outstanding voting stock of which is owned directly or indirectly, by
Energen.
(s) "Window Period" shall mean the 30-day period
immediately following the first anniversary of a Change in Control.
Section 2. Notice of Termination. During any Applicable Period:
(a) Any termination (other than for Retirement, death or
Disability) of Executive's employment, whether by Employer or Executive, shall
be communicated by the terminating party transmitting or sending the other
party a written notice ("Notice of
5
<PAGE> 6
Termination") referencing this Agreement and, if such termination is for Cause
or Good Reason, indicating in reasonable detail the facts and circumstances
providing a basis for such termination. The failure of Executive or Employer
to set forth in the Notice of Termination any fact or circumstance which
contributes to a showing of Good Reason or Cause shall not waive any right of
Executive or Energen hereunder or preclude Executive or Energen from asserting
or relying upon the omitted fact or circumstance in enforcing Executive's or
Energen's rights hereunder.
(b) Subject to (c) below, such termination of Executive's
employment shall be effective upon delivery of a Notice of Termination or at
such later date as may be specified in the Notice of Termination.
(c) In the event that each party delivers a Notice of
Termination, the Notice of Termination first delivered shall establish the
effective date of such Notice of Termination.
Section 3. Severance Payment. In the event of a Qualified
Termination, then Executive shall, subject to the provisions of Sections 5 and
8 hereof, receive as severance pay an amount equal to his Compensation
multiplied by a factor of [1.5 or 2 or 2.5]. Subject to Section 5 hereof, any
severance payment to be made under this Section 3 shall be paid in one payment
and in full on or prior to the thirtieth day following the Date of Termination.
Section 4. Other Benefits. Subject to Sections 5 and 8 hereof,
in the event of a Qualified Termination (other than Retirement), for a period
of twenty-four months commencing with the Date of Termination, Executive and
the Executive's family shall continue to be covered at the expense of Energen
by the same or substantially equivalent hospital, medical, dental, vision,
accident, disability and life insurance coverages as were provided to Executive
and the Executive's family by Employer immediately prior to the Change in
Control; provided, however, that if Executive becomes employed with another
employer and is eligible to receive benefits of the type described above from
such other employer, Energen's obligations under this Section 4 and the
benefits described herein shall be secondary to those provided by such other
employer.
Section 5. Limitation on Benefits.
(a) Basic Rule. Except as otherwise provided in
paragraph (c) below, any benefits payable or to be provided to the Executive by
Employer, whether pursuant to this Agreement or otherwise (including, without
limitation, Awards under the Energen Corporation 1992 or 1996 Long-Range
Performance Share Plans), which constitute Parachute Payments shall be modified
or reduced as provided in paragraph (b) below to the extent necessary so that
the benefits payable or to be provided to Executive under this Agreement that
constitute Parachute Payments, as well as any payments or benefits provided
outside of this Agreement that constitute Parachute Payments, shall not cause
Employer to have paid an Excess Parachute Payment. All provisions of Section
280G of the Code, and the regulations (proposed, interim, or final) thereunder,
shall be taken into account in computing such amount, including making
appropriate adjustment to such calculation for amounts established to be
Reasonable Compensation.
6
<PAGE> 7
(b) Reductions. In the event that the amount of any
Parachute Payment otherwise payable to or for the benefit of the Executive must
be modified or reduced to comply with paragraph (a) above, the Executive shall
direct which Parachute Payments are to be modified or reduced; provided,
however, that no increase in the amount of any payment or any change in the
timing of payment shall be made without the consent of Energen.
(c) Optimization. Prior to the first date any Parachute
Payment is due to be made, Energen shall, at its own expense, cause the
Independent Auditor to determine whether X exceeds Y, where
(i) X is the total amount of Parachute Payments
that would be made to the Executive, whether pursuant to this Agreement or
otherwise, if the limitation provided for in paragraph (a) above were not
applied, reduced by the total amount of applicable federal, state, and local
income, payroll and excise taxes that would be payable by the Executive with
respect to such Parachute Payments, and
(ii) Y is the total amount of Parachute Payments
that would be payable to the Executive, whether pursuant to this Agreement or
otherwise, if the limitation provided for in paragraph (a) above were applied,
reduced by the total amount of applicable federal, state and local income,
payroll and excise taxes that would be payable by the Executive with respect to
such Parachute Payments.
If X exceeds Y, then the limitation provided for in paragraph (a) above shall
not apply. For purposes of making the determination provided for in this
paragraph (c), the Independent Auditor shall assume that all Parachute Payments
to be made to the Executive will be subject to federal income tax at the
maximum rate in effect at the time the determination is made unless the
Executive provides the Independent Auditor with evidence satisfactory to the
Independent Auditor that it is more probable than not that one or more
Parachute Payments will be taxable at a lower rate, or lower rates, in which
case the Independent Auditor shall assume that such Parachute Payments will be
taxed at the lower rate or rates.
(d) Subsequent Payments. As a result of various
incentive or other plans, Executive may be entitled to receive various
Parachute Payments over a period of several years. In such event, the
Independent Auditor may need to update its Section 5(c) calculations one or
more times. In the event that all or a portion of a Parachute Payment is not
made due to the limitations of this Section 5, Energen shall not be relieved of
liability for such amount but such Parachute Payment shall be deferred and
included in calculations with respect to subsequent Parachute Payments.
(e) Overpayments and Underpayments. As a result of
uncertainty in the application of section 280G of the Code at the time of
determinations by the Independent Auditor hereunder, uncertainties in the
valuation of future payments, and deferrals pursuant to Section 5(d), it is
possible that Parachute Payments will have been made by Energen which should
not have been made (an "Overpayment") or that additional Parachute Payments
which will not have been made by Energen could have been made (an
"Underpayment"), consistent in each case
7
<PAGE> 8
with the other provisions of this Section 5. In the event that the Independent
Auditor, based upon the assertion of a deficiency by the Internal Revenue
Service against Energen or the Executive which the Independent Auditor believes
has a high probability of success, determines that an Overpayment has been
made, such Overpayment shall be treated for all purposes as a loan to the
Executive which the Executive shall repay to Energen, together with interest at
the applicable federal rate provided for in section 7872(f)(2)(A) of the Code;
provided, however, that no amount shall be payable by the Executive to Energen
if and to the extent that such payment would not reduce the amount which is
subject to taxation under section 4999 of the Code. In the event that the
Independent Auditor determines that an Underpayment has occurred, such
Underpayment shall promptly be paid or transferred by Energen to or for the
benefit of the Executive, together with interest at the applicable federal rate
provided for in section 7872(f)(2)(A) of the Code.
Section 6. No Obligation To Seek Further Employment; No Effect
on Other Benefits.
(a) Executive shall not be required to seek other
employment, nor (except as otherwise provided under Section 4 with respect to
insurance coverages) shall the amount of any severance payment or other benefit
to be made or provided under this Agreement be reduced by any compensation or
benefit earned by Executive as the result of employment by another employer
after the Date of Termination, or otherwise.
(b) Subject to Section 5 hereof, any severance payment or
benefit to be made or provided under this Agreement is in addition to all other
benefits, if any, to which Executive may be entitled under other agreements,
plans or programs of Energen.
Section 7. Continuing Obligations of Executive. As a result of
and in connection with Executive's employment by Employer, Executive is
involved in a number of matters of strategic importance and value to Employer
including various projects, proceedings, planning processes, and negotiations.
Any number of these matters may be ongoing and continuing after the Date of
Termination. In addition Employee is privy to proprietary and confidential
information of Employer including without limitation, financial information
and projections, business plans and strategies, customer and vendor lists and
information, and oil and gas properties and prospects. The Executive agrees as
follows:
(a) Consulting Services. For a period of three years
following the Date of Termination, Executive agrees to fully assist and
cooperate with Employer and its representatives (including outside auditors,
counsel and consultants) with respect to any matters with which the Executive
was involved during the course of employment with Employer, including being
available upon reasonable notice for interviews, consultation, and litigation
preparation. Except as otherwise agreed by Executive, Executive's obligation
under this Section 7 (a) shall not exceed 80 hours during the first year and 20
hours during each of the following two years. Such services shall be provided
upon request of Employer but scheduled to accommodate Executive's reasonable
scheduling requirements. Executive shall receive no additional fee for such
services but shall be reimbursed all reasonable out-of-pocket expenses.
8
<PAGE> 9
(b) Non-Compete. For a period of twelve months following
the Date of Termination, the Executive shall not Compete, (as defined below)
or assist others in Competing with the Employer. For purposes of this
Agreement, "Compete" means (i) solicit in competition with Alabama Gas
Corporation ("Alagasco") any person or entity which was a customer of Alagasco
at the Date of Termination, (ii) offer to acquire any local gas distribution
system in the State of Alabama; or (iii) offer to acquire any coalbed methane
interest in the State of Alabama. Employment by, or an investment of less than
one percent of equity capital in, a person or entity which Competes with
Employer does not constitute Competition by Executive so long as Executive does
not directly participate in, assist or advise with respect to such Competition.
(c) Confidentiality. Executive agrees that at all times
following the Date of Termination, Executive will not, without the prior
written consent of Energen, disclose to any person, firm or corporation any
confidential information of Employer which is now known to Executive or which
hereafter may become known to Executive as a result of Executive's employment
or association with Employer, unless such disclosure is required under the
terms of a valid and effective subpoena or order issued by a court or
governmental body; provided, however, that the foregoing shall not apply to
confidential information which becomes publicly disseminated by means other
than a breach of this Agreement.
Section 8. Board Resignation. Energen shall have no obligation
under Sections 3 and 4 hereof if Executive shall not, promptly after the Date
of Termination and upon receiving a written request to do so, resign from each
officer and/or director position which Executive then holds with Energen and
any Subsidiary.
Section 9. Payment of Professional Fees and Expenses. Energen
agrees to pay promptly as incurred, to the full extent permitted by law, all
legal, accounting and other professional fees and expenses which Executive may
reasonably incur (i) as a result of any contest (regardless of the outcome
thereof) by Energen, Executive or others of the validity or enforceability of,
or liability under, any provision of this Agreement or any guarantee of
performance thereof (including as a result of any contest by Executive about
the amount of any payment pursuant to this Agreement); plus in each case
interest on any delayed payment at the applicable Federal rate provided for in
Section 7872(f)(2)(A) of the Code; or (ii) as a result of any contest by a
taxing authority of Executive's tax treatment of any amounts received under
this or any other Employer agreement or plan to the extent such tax treatment
is consistent with the determinations made by the Independent Auditor under
Section 5.
Section 10. Term. This Agreement shall terminate (except to the
extent of any unpaid or unfulfilled obligation with respect to a prior
termination of Executive's employment) on the first to occur of (i) any
termination of Executive's employment with Employer which does not constitute a
Qualified Termination or (ii) expiration of the Term. The initial "Term" of
this Agreement shall be for a period of three years from the date hereof. On
each anniversary of the date hereof, the Term shall automatically extend by one
year unless at least thirty days prior to such an anniversary Energen notifies
Executive that there will be no such extension, in which event the term shall
continue until the later to occur of (i) two years from such anniversary or
(ii) three years from the date of the most recent Change in Control, if any.
9
<PAGE> 10
Section 11. Binding Effect; Successors.
(a) This Agreement shall be binding upon and inure to the
benefit of Executive and Executive's personal representative and heirs, and
Energen and its successors and assigns including any successor organization or
organizations which shall succeed to substantially all of the business and
property of Energen, whether by means of merger, consolidation, acquisition of
assets or otherwise, including operation of law.
(b) Without the prior consent of Energen, Executive may
not assign the Agreement, except by will or the laws of descent and
distribution.
Section 12. Notice. For purposes of this Agreement, notices and
all other communications provided for in this Agreement shall be in writing and
shall be deemed to have been duly given when delivered or mailed by United
States registered mail, return receipt requested, postage prepaid, as follows:
If to Energen or Employer:
Energen Corporation
2101 Sixth Avenue North
Birmingham, Alabama 35203
Attention: Chairman
If to Executive:
------------------------------
------------------------------
------------------------------
or such other address as either party may have furnished to the other in
writing in accordance herewith, except that notices of change of address shall
be effective only upon receipt.
Section 13. Miscellaneous. No provisions of this Agreement may
be modified, waived or discharged unless such waiver, modification or discharge
is agreed to in writing signed by Executive and Energen. No waiver by either
party hereto at any time of any breach by the other party hereto of, or
compliance with, any condition or provision of this Agreement to be performed
by such other party shall be deemed a waiver of similar or dissimilar
provisions or conditions at the same or at any prior or subsequent time. No
agreements or representations, oral or otherwise, express or implied, with
respect to the subject matter hereof have been made by either party which are
not set forth expressly in this Agreement. This Agreement shall be governed by
and construed in accordance with the laws of the State of Alabama.
Section 14. Validity. The invalidity or unenforceability of any
provisions of this Agreement shall not affect the validity or enforceability of
any other provision of this Agreement, which shall remain in full force and
effect.
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<PAGE> 11
Section 15. Counterparts. This Agreement may be executed in one
or more counterparts, each of which shall be deemed to be an original but all
of which together will constitute one and the same instrument.
Section 16. Amendment and Restatement of Prior Agreement. This
agreement constitutes a complete amendment and restatement and fully supersedes
that certain Severance Compensation Agreement between the parties dated
____________________, 19__.
IN WITNESS WHEREOF, the parties have executed this Agreement
as of the date first above written.
ENERGEN CORPORATION
By
-------------------------------------
Its
-------------------------------------
EXECUTIVE
----------------------------------------
11
<PAGE> 1
EXHIBIT 13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS
OF OPERATIONS AND FINANCIAL CONDITION
RESULTS OF OPERATIONS
CONSOLIDATED NET INCOME
Energen Corporation's net income for the 1996 fiscal year was $21.5 million, or
$1.95 per share. This represented a 10 percent increase in per share earnings
over prior year net income of $19.3 million, or $1.77 per share, and resulted
from the continued financial and operating strength of Alabama Gas
Corporation's (Alagasco's) utility operations combined with significant growth
at Taurus Exploration Inc. (Taurus), Energen's nonregulated oil and gas
subsidiary. In 1994 Energen reported earnings of $23.8 million, or $2.19 per
share, including a one-time gain of $2 million, or 18 cents per share, for the
sale of propane assets and a reduction in investment in high temperature
combustion technology.
1996 VS 1995: Alagasco achieved record net income for a sixth consecutive
year, increasing to $17.0 million over prior-year earnings of $15.7 million.
This 8 percent growth in income reflected the utility's ability to earn within
its allowed range of return on an increased level of equity. Fiscal 1995
earnings included a one-time after-tax charge of $503,000 resulting from a
voluntary early retirement program.
Taurus's net income grew 28.5 percent to $4.5 million on the strength of
increased oil and gas production, higher commodity sales prices and gains on
the sale of reserves; negatively influencing Taurus's earnings were increases
in production-related expenses, primarily depreciation, depletion and
amortization (DD&A) as well as increased interest and exploration expenses.
1995 VS 1994: Alagasco's 1995 net income of $15.7 million increased 5.4
percent over 1994 net income of $14.9 million primarily due to the utility
earning for a full year on a higher level of equity generated by a $21 million
investment in underground storage working gas made in 1994; the utility
received a $10 million equity infusion from Energen to help fund the
investment. The one-time charge for the voluntary early retirement program in
fiscal 1995 partially offset this increase. Taurus earned net income of $3.5
million in 1995, a decrease of 46 percent from 1994. The major factor
negatively affecting Taurus's earnings was comparatively lower natural gas
commodity prices which affected Taurus's gas production revenues as well as
income from price-sensitive coalbed methane operating fees. Taurus's 1995
earnings also were negatively impacted by increased operating and DD&A expenses.
OPERATING INCOME
Consolidated operating income in 1996, 1995, and 1994 totaled $38.8 million,
$32.0 million and $35.3 million, respectively. In the current year, operating
income was influenced significantly by Taurus as it implemented Energen's
growth strategy and recognized a gain on the sale of reserves. Growth in
Alagasco's operating income was consistent with its increased level of equity.
Operating income in 1995 was impacted by lower natural gas commodity prices and
increased operating expense at Taurus.
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<PAGE> 2
ALAGASCO: Alagasco generates revenues through the sale and transportation of
natural gas. Shifts between transportation and sales gas can cause large
variations in natural gas revenues since the transportation rate does not
contain an amount representing the cost of gas. Alagasco's rate structure
allows similar margins on transported and sales gas; therefore, operating
income is not adversely affected. Weather also can cause variations in
revenues, but operating margins remain unaffected due to a real-time
temperature adjustment which allows Alagasco to adjust customer bills monthly
to reflect changes in usage due to departures from normal weather.
Alagasco's gross natural gas sales revenues totaled $326.8 million, $265.5
million, and $315.3 million in 1996, 1995, and 1994, respectively. Several
factors contributed to the 23 percent current-year increase in sales revenues
including the influence of significantly colder weather on total throughput and
higher commodity gas costs passed through to customers in rates. As a result of
Alagasco's temperature adjustment mechanism, however, the margins associated
with the colder weather were removed via an adjustment to customer bills. In
1995 pricing and weather had the opposite impact as lower prices and warmer
weather resulted in substantially lower revenues.
Alagasco's coldest winter in 18 years coupled with steady demand for commercial
and industrial sales and transportation volumes led to a new gas throughput
record of 111 Bcf in 1996. Residential sales volumes increased 27 percent in
the current year as weather in Alagasco's service area was 13 percent colder
than normal and 40 percent colder than the prior year. Sales and transportation
volumes to commercial and industrial customers totaled 76.5 Bcf in 1996 and 74
Bcf in 1995. While volumes to large customers remained relatively stable, small
commercial and industrial customers, more sensitive to weather, experienced
volume increases similar to residential customers. In 1995 residential volumes
decreased significantly due to weather which was 19 percent warmer than normal.
The addition of several large customers that year resulted in a 12 percent
increase in throughput to commercial and industrial customers.
Higher commodity gas cost and higher sales volumes resulting from the cold
weather in fiscal 1996 generated a 36 percent increase in cost of gas.
Conversely, lower prices and sales volumes in a warm year created the
significant decrease in 1995.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, (DOLLARS IN THOUSANDS) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Gross natural gas sales revenues ..................................... $ 326,844 $ 265,477 $ 315,317
Cost of natural gas ................................................... (181,400) (133,556) (188,592)
Revenue taxes ....................................................... (20,055) (16,051) (20,018)
- -----------------------------------------------------------------------------------------------------------------------
Net natural gas sales margin ......................................... 125,389 115,870 106,707
Net natural gas transportation margin ................................. 30,408 30,490 29,320
- -----------------------------------------------------------------------------------------------------------------------
Net natural gas sales and transportation margin ....................... $ 155,797 $ 146,360 $ 136,027
- -----------------------------------------------------------------------------------------------------------------------
Natural gas sales volumes (MMcf)
Residential ....................................................... 34,963 27,489 31,254
Commercial and industrial-small ................................... 14,972 12,288 13,536
Commercial and industrial-large ................................... 30 29 106
- -----------------------------------------------------------------------------------------------------------------------
Total natural gas sales volumes ..................................... 49,965 39,806 44,896
Natural gas transportation volumes (Mmcf) ........................... 61,458 61,640 52,635
- -----------------------------------------------------------------------------------------------------------------------
Total deliveries (Mmcf) ............................................... 111,423 101,446 97,531
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
24
<PAGE> 3
Several items contributed to the 5 percent increase in operations and
maintenance (O&M) expense at the utility in 1996. Distribution expenses, which
include labor and maintenance costs, increased as a result of
colder-than-normal weather. Secondly, to reflect its increased exposure from
higher commodity gas costs in accounts receivable, Alagasco increased its
provision for doubtful accounts. Thirdly, the utility increased its marketing
efforts over the previous year. Partially offsetting these items was the
inclusion in the prior year and the resulting savings in the current year of
expense associated with an early retirement option. On a per customer basis,
the increase in O&M fell within the inflation-based cap established by the
Alabama Public Service Commission (APSC) as part of the utility's rate-setting
mechanism. In 1995 increased labor and related expenses, including the early
retirement charge, created the majority of the 7 percent increase. As a result
of these costs, O&M expense per customer exceeded the cap and a portion of the
excess was returned to customers.
Consistent with growth in the utility's depreciable base, depreciation expense
rose 9.8 percent in 1996 and 8 percent in 1995. 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.
As discussed more fully in Note 2 to the Consolidated Financial Statements,
Alagasco is subject to regulation by the APSC. On October 7, 1996, the APSC
issued an order to extend the Company's rate-setting mechanism for a five-year
period through January 1, 2002. Under the terms of that extension, RSE will
continue after January 1, 2002, unless, after notice to the Company and a
hearing, the Commission votes to either modify or discontinue its operation.
TAURUS: Revenues from oil and gas production activities grew notably in the
first year of Taurus's aggressive growth strategy. Total production volumes
rose 60 percent to 16.1 Bcfe and included production from new acquisitions as
well as the addition of prior-year offshore discoveries. Natural gas
production, including coalbed methane, increased 43 percent to 12.3 Bcf. Oil
volumes increased to 635 MBbl from 250 MBbl. Higher oil and gas prices
magnified the impact of increased production. Gas prices rose 14.5 percent to
$1.97 per Mcf, while oil prices increased 8 percent to $16.25 per barrel.
Reflected in those prices is the effect of Taurus hedging or placing under
contract 66 percent of its production at an average price of $2.00 per Mcf and
$18.30 per barrel, before consideration of any related basis differential.
Coalbed methane operating fees represent a percentage of net proceeds on
certain coalbed methane 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 in 1996 increased 14
percent to $3.8 million largely due to higher natural gas prices. Coalbed
methane consulting revenues decreased significantly in the current year as
Taurus completed several contracts.
Under Energen's aggressive growth strategy, Taurus may, in the ordinary course
of business, be involved in the sale of both developed and undeveloped
properties as a revenue source. With respect to developed properties, sales may
occur as a result of, but not limited to, disposing of marginal assets, and
accepting offers where the buyer gives greater value to a property than
Taurus's technical staff. The largest of several property sales in 1996
occurred in September when Taurus recorded a $3.2 million gain after selling
its working interest in reserves associated with PMC Reserve Acquisition
Company.
25
<PAGE> 4
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, (DOLLARS IN THOUSANDS, EXCEPT UNIT PRICE) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues
Natural gas production ............................................... $24,262 $14,748 $17,292
Oil production ....................................................... 10,313 3,765 2,725
Operating and consulting fees ....................................... 4,100 4,373 5,194
Other ............................................................... 3,949 769 --
- -----------------------------------------------------------------------------------------------------------------------
Total Revenues ......................................................... $42,624 $23,655 $25,211
- -----------------------------------------------------------------------------------------------------------------------
Production volumes
Natural gas (Mmcf) ................................................... 12,308 8,597 9,169
Oil (Mbbl) ........................................................... 635 250 191
- -----------------------------------------------------------------------------------------------------------------------
Average unit sales price
Natural gas (per Mcf) ............................................... $ 1.97 $ 1.72 $ 1.89
Oil (per Bbl) ....................................................... $ 16.25 $ 15.07 $ 14.25
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
Weak natural gas prices had the greatest impact on production revenues in
fiscal 1995. Although Taurus hedged 65 percent of its natural gas production at
$2.06 per Mcf (before basis differential), the average sales price was $1.72
per Mcf, a decline of 9 percent from the previous year. Production revenues
also were affected by a 6 percent decrease in volumes resulting from lower
offshore production caused in part by the timing of production schedules. Oil
revenues benefitted from an increase in volumes and prices. Operating fees were
$1.1 million lower in 1995 primarily due to lower prices. Consulting fees were
slightly higher due to the inclusion of revenues from a new contract. Also
included in 1995 revenues was a $769,000 gain associated with the buy out of a
long-term sales contract.
Operations expense increased $4.3 million in 1996 primarily due to Taurus's
acquisition and exploration strategy. Lease operating expense was significantly
higher because of current-year acquisitions plus an entire year's activity
related to fiscal 1995 acquisitions. Additionally, exploration expense
increased as a result of Taurus's expanded exploratory efforts. In 1995
operations expense increased $3 million primarily due to increased labor and
related expense, exploration expense and administrative expense.
DD&A expense rose $9.6 million from the prior year largely due to increased
production (16.1 Bcf in 1996 compared to 10.1 Bcf in 1995). In addition, the
average depletion rate of $1.15 per Mcf increased from $0.88 per Mcf in 1995 as
a result of reserve revisions and property write-downs. For 1995 the 8 percent
increase in DD&A was due largely to an increased average depletion rate ($0.78
per Mcf in 1994) associated with downward reserve revisions.
OTHER ACTIVITIES AND INTERCOMPANY ELIMINATIONS: Operating income from Energen's
group of other activities did not vary significantly in 1996. The notable
decrease in 1995 was due almost exclusively to the absence of contribution from
propane activities following the sale of the Company's propane assets in June
1994. Intercompany eliminations relate to intercompany natural gas sales and
vary based on pricing and volumes.
26
<PAGE> 5
NON-OPERATING ITEMS
CONSOLIDATED: Fiscal 1996 interest expense increased $2.2 million primarily
due to the financing of Taurus's aggressive acquisition strategy, largely
through the use of the Company's short-term credit facilities. The average
daily outstanding balance under the short-term credit facilities was $38
million compared to $0.9 million in the prior year. Also influencing the
current year was interest for a full year on $50 million of medium-term notes
(MTNs) issued in mid-1995 and, to a lesser degree, the issuance of $65 million
of MTNs in the fourth quarter of fiscal 1996. Interest expense in 1995
increased 4 percent over 1994 due primarily to the $50 million of MTNs
discussed above, offset to some degree by the repayment of $6.3 million of
notes payable and lower average short-term debt outstanding.
The decrease in total other income in the current year was largely due to the
inclusion of the amortization of the early call premium associated with the
redemption of debt in the prior year. Other income in 1995 decreased
significantly from 1994 as a result of pre-tax gains associated with the 1994
sale of the Company's propane assets ($2.1 million) and the sale of the
Company's investment in equity securities ($1.5 million).
The Company's effective tax rates in 1996, 1995, and 1994 were lower than
statutory federal tax rates primarily due to the recognition of nonconventional
fuel tax credits and the amortization of investment tax credits. Changes in
income tax expense in both years resulted primarily from changes in pre-tax
income. The Company's effective tax rates are expected to remain lower than
statutory federal rates through December 31, 2002, as tax credits generated
each year are expected to be fully recognized in the financial statements.
FINANCIAL POSITION AND LIQUIDITY
The Company's net cash from operating activities totaled $52.5 million, $60.9
million, and $34.3 million in 1996, 1995, and 1994, respectively. Colder
weather in 1996 impacted cash provided by operations through its effect on gas
supply costs as reflected in increased accounts receivable and payable and in
Alagasco's need to utilize and replenish its storage gas inventory.The receipt
of amounts from Southern Natural Gas Company and other suppliers in settlement
of matters before the FERC (see Note 2 to the Consolidating Financial
Statements) positively affected cash flows in the current year. The increase in
operating cash flow in 1995 primarily is due to the net cash outflow of $23.5
million in 1994 to purchase storage gas at Alagasco. For both years, cash flow
was affected by fluctuations in other receivables and payables which are
generally the result of timing of payments.
Cash used in investing activities increased $84.5 million and $39.6 million in
1996 and 1995, respectively, largely due to the implementation of Energen's
diversified growth strategy. In 1996 Taurus invested $108 million in property
acquisitions with development potential adding 178 Bcfe of proved developed and
undeveloped oil and gas reserves. Current-year acquisitions include the $61
million purchase of 105 Bcf of coalbed methane reserves in Alabama. Prior-year
acquisitions totaled $16.9 million and added 26.8 Bcfe to proved reserves.
Taurus sold its entire working interest in reserves associated with the PMC
acquisition venture in 1996 resulting in cash proceeds of $13.1 million.
Proceeds of $13.4 million for the 1994 sale of both propane assets and equity
securities contributed to the increase in cash used in 1995.
Cash provided by financing activities totaled $80 million in 1996. The Company
issued $40 million of MTNs redeemable September 20, 2001, to September 15,
2026, with interest rates ranging from 7.1 percent to 8.1 percent. The Company
utilized
27
<PAGE> 6
an additional $26.7 million in short-term credit facilities. Proceeds from
these issuances were used to finance the acquisition strategy at Taurus. Also
included in current-year financing activities were the proceeds from the
issuance of $25 million in Alagasco MTNs redeemable December 1, 1998, to
September 23, 2026, with interest rates ranging from 5.6 percent to 8 percent.
These proceeds will be used for customer refunds (see Note 2 to the
Consolidated Financial Statements), gas storage inventory replacement, and
facilities upgrade and acquisition. Cash provided by financing activities in
1995 was $15.9 million and included the issuance of $50 million in Alagasco
MTNs used to defease a portion of its long-term debt (see Note 3 to the
Consolidated Financial Statements). In 1994 cash provided by financing
activities was $6.2 million and included the issuance of 550,000 shares of
Energen common stock and $50 million in Alagasco MTNs. Proceeds from these
issuances were used to fund the purchase of underground storage gas, redeem
other long-term debt, and fund additional capital needs.
CAPITAL EXPENDITURES
NATURAL GAS DISTRIBUTION: During the last three fiscal years, Alagasco has
invested $124.4 million for capital projects: $95.9 million was spent on normal
expansion replacements and support of its distribution system; $14.6 million
was used in connection with the development of a new customer information
system; $6.5 million was used to improve gas availability; and $7.5 million was
used to purchase five municipal gas systems.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Capital expenditures for:
Renewals, replacements, system expansion and other ................... $35,064 $30,611 $30,264
Additions to improve gas availability ............................... 1,799 3,024 1,644
Municipal gas system acquisitions ................................... 3,305 3,972 178
Customer information system ......................................... 3,007 5,173 6,387
- -----------------------------------------------------------------------------------------------------------------------
Total ............................................................. $43,175 $42,780 $38,473
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
EXPLORATION AND PRODUCTION: Taurus has spent $167.9 million for capital
projects over the last three fiscal years, $7.8 million of which was charged to
income as exploration expense. Expenditures for property acquisitions were
$130.5 million, exploratory expenditures totaled $17.7 million, and $17.5
million was spent in development activities.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Capital and exploration expenditures for:
Property acquisitions ............................................... $110,008 $17,939 $2,541
Exploration ......................................................... 9,855 3,794 4,091
Development ......................................................... 10,040 6,044 1,438
Other ............................................................... 583 716 900
- -----------------------------------------------------------------------------------------------------------------------
Total ............................................................. $130,486 $28,493 $8,970
- -----------------------------------------------------------------------------------------------------------------------
Exploration expenditures charged to income (included above) ........... $ 4,169 $ 2,064 $1,614
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
28
<PAGE> 7
OTHER ACTIVITIES: Capital expenditures by Energen's other activities totaled
$1.3 million in the last three fiscal years and primarily related to gathering
activities.
FUTURE CAPITAL RESOURCES AND LIQUIDITY
Utility capital expenditures could approximate $37.6 million in 1997 and
primarily represent additions for normal distribution system expansion.
Alagasco also will maintain an investment in storage working gas which is
expected to average approximately $24 million in 1997. Alagasco anticipates
funding these capital requirements through internally generated capital and the
utilization of short-term credit facilities.
The Company's strategy to dramatically grow its oil and gas exploration and
production subsidiary involves investing $400 million in the acquisition of
producing properties with development potential and $100 million in offshore
Gulf of Mexico exploration and development in the five-year period ending
September 30, 2000. During 1997 Taurus plans to invest $90 million in property
acquisitions and in the development of existing reserves and $20 million in
offshore exploration and development. It should be noted that Taurus's ability
to invest in property acquisitions will be significantly influenced by industry
trends as the producing property acquisition market has historically been
cyclical. To finance Taurus's investment program, the Company initially will
utilize short-term credit facilities of $156 million to supplement internally
generated cash flow, but long-term debt and equity will be issued for permanent
financing. During fiscal 1996, Energen filed a $250 million shelf registration
for debt and common stock. MTNs of $40 million were issued in September 1996,
and the Company plans to offer a combination of debt and equity during the
second fiscal quarter of 1997.
OUTLOOK
NATURAL GAS DISTRIBUTION: A recent five-year extension of the utility's
rate-setting mechanism gives Alagasco the opportunity to continue earning a
return on average equity at year-end within a range of 13.15 percent to 13.65
percent. Alagasco has previously implemented and will continue to utilize
flexible rate strategies to help compete effectively for large commercial and
industrial customer load in the deregulated marketplace and combat
fuel-switching and the threat of bypass of the distribution system. To
supplement traditional service area growth, the utility will continue to pursue
the acquisition of municipal gas systems in Alabama. Although residential
unbundling is being considered by some in the industry as a potential means to
improve efficiency and achieve market-driven pricing, Energen believes that
electric and gas utility market competition in Alabama already fulfills that
purpose for Alagasco; however, the Company will continue to assess the
advisability of residential unbundling.
EXPLORATION AND PRODUCTION: Taurus's oil and gas production is expected to
increase 70 percent to more than 27 Bcfe in 1997. Seventy-two percent of
production is expected to come from currently producing wells; another 17
percent should be generated by existing wells coming on-line during the year;
and 11 percent is targeted from new acquisitions to be made in 1997. To hedge
its exposure to price fluctuations, Taurus has entered into futures contracts
or placed under sales contracts 70 percent of estimated gas production at an
average price of $2.18 per Mcf. Taurus also has hedged more than half of its
estimated oil production at $20.98 per barrel. Hedge prices do not reflect
basis differential. Coalbed methane production during 1997 is expected to
generate more than $6 million in tax credits.
29
<PAGE> 8
OTHER: Certain of the statements set forth above contain forward-looking
information. Such statements involve risks and uncertainties, and there are
certain important factors that could cause actual results to differ materially
from those anticipated. Some of these important factors include, but are not
limited to, economic and competitive conditions, inflation, rates, regulatory
changes, financial market conditions, future business decisions, and other
uncertainties, all of which are difficult to predict and most of which are
beyond the control of the Company. 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, including many
factors beyond the control of the Company. As discussed in Note 12 to the
Consolidated Financial Statements, the total amount or timing of actual future
production may vary significantly from the amount of reserves disclosed. In the
event Taurus is unable to fully invest its planned acquisition expenditures,
operating revenues and proved reserves would be negatively affected. The
Company's results of operations and cash flows also could be affected by
changing oil and gas prices. Although Taurus makes use of futures contracts to
mitigate risk, fluctuations in oil and gas prices may affect the Company's
financial position.
RECENT PRONOUNCEMENTS OF THE FASB
During fiscal 1997, the Company is required to adopt two Statements issued in
1995 by the Financial Accounting Standards Board. Statement of Financial
Accounting Standard (SFAS) No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, requires
long-lived assets be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount for an asset may not be
recoverable. Based on known facts and circumstances, its adoption is not
expected to have a material impact on the Company's financial statements. SFAS
No. 123,Accounting for Stock-Based Compensation, establishes a fair
value-based method of accounting for employee stock options but allows
companies to continue to follow the accounting treatment prescribed by APB
Opinion 25 with proper disclosure. The Company has not yet determined the
method of accounting that it will follow for stock options but does not expect
the requirements of SFAS No. 123 to have a material impact on the Company's
financial statements. In June 1996, SFAS No. 125, Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities, was issued
and provides accounting and reporting standards for such transactions. The
Company is required to adopt this Statement in fiscal 1998, and it is not
expected to have a material impact on the Company's financial statements.
QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------
QUARTER ENDED (IN DOLLARS) High Low Close Dividends Paid
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
December 31, 1994 ................................................... 22 3/4 19 3/4 22 .28
March 31, 1995 ..................................................... 23 1/2 20 5/8 22 7/8 .28
June 30, 1995 ....................................................... 23 1/4 20 1/8 21 1/2 .28
September 30, 1995 ................................................. 22 3/8 21 21 3/4 .29
- ------------------------------------------------------------------------------------------------------------------------
December 31, 1995 ................................................... 25 1/8 21 3/8 24 1/8 .29
March 31, 1996 ..................................................... 25 3/8 21 3/4 21 7/8 .29
June 30, 1996 ....................................................... 24 1/4 21 7/8 22 1/8 .29
September 30, 1996 ................................................. 25 22 24 .30
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
30
<PAGE> 9
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
ENERGEN CORPORATION AND SUBSIDIARIES
- -----------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS, EXCEPT SHARE DATA) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Natural gas distribution ................................................... $ 357,252 $ 295,967 $ 344,637
Oil and gas production activities ........................................... $ 42,624 23,655 25,211
Other ....................................................................... 2,158 2,298 8,810
Intercompany eliminations ................................................... (2,592) (3,340) (4,155)
- -----------------------------------------------------------------------------------------------------------------------
Total operating revenues ............................................... 399,442 318,580 374,503
- -----------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas ................................................................. 178,810 130,220 184,458
Operations ................................................................. 100,822 93,293 89,829
Maintenance ................................................................. 11,078 9,849 9,469
Depreciation, depletion and amortization ................................... 41,118 29,556 27,976
Taxes, other than income taxes ............................................. 28,817 23,629 27,443
- -----------------------------------------------------------------------------------------------------------------------
Total operating expenses ............................................... 360,645 286,547 339,175
- -----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME ........................................................... 38,797 32,033 35,328
- -----------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense, net of amounts capitalized ............................... (13,920) (11,693) (11,284)
Gain on sale of assets ..................................................... -- -- 2,142
Other, net ................................................................. 1,712 2,649 4,176
- -----------------------------------------------------------------------------------------------------------------------
Total other income (expense) ........................................... (12,208) (9,044) (4,966)
- -----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES ................................................. $ 26,589 $ 22,989 $ 30,362
Income taxes ............................................................... 5,048 3,681 6,611
- -----------------------------------------------------------------------------------------------------------------------
NET INCOME ................................................................. $ 21,541 $ 19,308 $ 23,751
- -----------------------------------------------------------------------------------------------------------------------
EARNINGS PER AVERAGE COMMON SHARE ........................................... $ 1.95 $ 1.77 $ 2.19
- -----------------------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING ........................................... 11,023,434 10,906,315 10,833,619
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
31
<PAGE> 10
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
ENERGEN CORPORATION AND SUBSIDIARIES
- -----------------------------------------------------------------------------------------------------------------------
AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant ............................................................................. $544,643 $504,371
Less accumulated depreciation ............................................................. 268,110 247,926
- -----------------------------------------------------------------------------------------------------------------------
Utility plant, net ................................................................... 276,533 256,445
- -----------------------------------------------------------------------------------------------------------------------
Oil and gas properties, successful efforts method ......................................... 224,469 117,339
Less accumulated depreciation, depletion and amortization ................................. 60,152 51,170
- -----------------------------------------------------------------------------------------------------------------------
Oil and gas properties, net ............................................................... 164,317 66,169
- -----------------------------------------------------------------------------------------------------------------------
Other property, net ....................................................................... 4,066 4,650
- -----------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment, net ................................................. 444,916 327,264
- -----------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents ................................................................. 17,074 36,695
Accounts receivable, net of allowance for doubtful accounts of
$3,002 in 1996 and $2,533 in 1995 ................................................... 42,353 30,813
Inventories, at average cost
Storage gas inventory ................................................................. 28,214 20,276
Materials and supplies ............................................................... 7,704 7,711
Liquified natural gas in storage ..................................................... 2,417 3,539
Deferred income taxes ..................................................................... 7,995 9,667
Prepayments and other ..................................................................... 9,538 10,330
- -----------------------------------------------------------------------------------------------------------------------
Total current assets ..................................................................... 115,295 119,031
- -----------------------------------------------------------------------------------------------------------------------
OTHER ASSETS
Deferred charges and other ............................................................... 10,760 12,789
- -----------------------------------------------------------------------------------------------------------------------
Total other assets ................................................................... 10,760 12,789
- -----------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS ............................................................................. $570,971 $459,084
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
32
<PAGE> 11
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITAL AND LIABILITIES
CAPITALIZATION
Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized ................... $ -- $ --
Common shareholders equity
Common stock, $0.01 par value; 30,000,000 shares authorized,
11,162,634 shares outstanding in 1996 and 10,921,733 shares
outstanding in 1995 ................................................................... 112 109
Premium on capital stock ................................................................. 86,833 81,243
Capital surplus ......................................................................... 2,802 2,802
Retained earnings ....................................................................... 98,658 90,020
Treasury stock, at cost (11,627 shares in 1995) ........................................... -- (250)
- -----------------------------------------------------------------------------------------------------------------------
Total common shareholder's equity ....................................................... 188,405 173,924
Long-term debt ............................................................................. 195,545 131,600
- -----------------------------------------------------------------------------------------------------------------------
Total capitalization ................................................................... 383,950 305,524
- -----------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Long-term debt due within one year ......................................................... 1,805 1,775
Notes payable to banks ..................................................................... 59,000 32,300
Accounts payable ........................................................................... 32,659 32,242
Accrued taxes ............................................................................... 17,567 11,339
Customer's deposits ......................................................................... 17,364 18,218
Amounts due customers ....................................................................... 17,746 16,546
Accrued wages and benefits ................................................................. 11,584 10,955
Other ....................................................................................... 18,049 14,923
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities ............................................................... 175,774 138,298
- -----------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes ....................................................................... 972 2,540
Other ....................................................................................... 10,275 12,722
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities ........................................... 11,247 15,262
- -----------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES ............................................................... -- --
- -----------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL AND LIABILITIES ............................................................... $570,971 $459,084
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
33
<PAGE> 12
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
<TABLE>
<CAPTION>
ENERGEN CORPORATION AND SUBSIDIARIES
- ----------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
- ----------------------------------------------------------------------------------------------------------------------------
Common Stock Treasury Stock
----------------------- ---------------------
Number of Par Premium on Capital Retained Number of
Shares Value Capital Stock Surplus Earnings Shares Cost
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE AT SEPTEMBER 30, 1993 10,320,317 $103 $66,368 $2,802 $71,040 -- $ --
Net income 23,751
Shares issued for:
Stock Offering 550,000 6 13,531
Dividend reinvestment plan 7,717 181
Employee benefit plans 39,870 993
Cash dividends -- $1.09 per share (11,749)
- ----------------------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1994 10,917,904 109 81,073 2,802 83,042 -- --
Net income 19,308
Purchase of treasury shares (128,900) (2,721)
Shares issued for:
Dividend reinvestment plan 14 19,035 394
Employee benefit plans 3,829 156 98,238 2,077
Cash dividends -- $1.13 per share (12,330)
- ----------------------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1995 10,921,733 109 81,243 2,802 90,020 (11,627) (250)
Net income 21,541
Purchase of treasury shares (86,900) (1,985)
Shares issued for:
Dividend reinvestment plan 80,529 1 1,827 66,552 1,511
Employee benefit plans 160,372 2 3,763 31,975 724
Cash dividends - $1.17 per share (12,903)
- ----------------------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1996 11,162,634 $112 $86,833 $2,802 $98,658 -- $ --
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
34
<PAGE> 13
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
ENERGEN CORPORATION AND SUBSIDIARIES
- -----------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income ............................................................... $ 21,541 $19,308 $23,751
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization ............................... 41,118 29,556 27,976
Deferred income taxes, net ............................................. (672) (2,061) (2,802)
Deferred investment tax credits, net ................................... (486) (487) (487)
Gain on sale of assets ................................................. -- -- (2,142)
Gain on sale of equity securities ..................................... -- -- (2,878)
Net change in:
Accounts receivable ................................................. (11,540) 3,332 1,523
Inventories ......................................................... (6,809) 3,775 (23,467)
Deferred gas cost ................................................... (549) 34 1,505
Accounts payable gas purchases ....................................... (1,614) 9,882 1,220
Accounts payable trade ............................................... 2,031 (5,120) (1,349)
Supplier refunds due customers ....................................... 13,942 2,483 92
Other current assets and liabilities ................................. (2,272) (3,290) 14,201
Other, net ............................................................. (2,233) 3,457 (2,800)
- -----------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities ........................... 52,457 60,869 34,343
- -----------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property, plant and equipment ............................... (168,414) (68,940) (45,543)
Proceeds from sale of assets ............................................. 13,134 -- 8,624
Proceeds from sale of equity securities ................................... -- -- 4,808
Payments on notes receivable ............................................. 1,557 816 1,639
Other, net ............................................................... 1,627 501 2,485
- -----------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities ............................... (152,096) (67,623) (27,987)
- -----------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Payment of dividends on common stock ..................................... (12,903) (12,330) (11,749)
Issuance of common stock ................................................. 4,645 84 14,711
Purchase of treasury stock ............................................... (1,985) (2,721) --
Reduction of long-term debt ............................................... (1,025) (45,070) (12,470)
Proceeds from issuance of long-term debt ................................. 64,586 49,660 49,670
Net change in short-term debt ............................................. 26,700 26,300 (34,000)
- -----------------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities ........................... 80,018 15,923 6,162
- -----------------------------------------------------------------------------------------------------------------------
Net change in cash and cash equivalents ................................... (19,621) 9,169 12,518
Cash and cash equivalents at beginning of period ......................... 36,695 27,526 15,008
- -----------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period ............................... $ 17,074 $36,695 $27,526
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
35
<PAGE> 14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ENERGEN CORPORATION AND SUBSIDIARIES
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Energen Corporation (the Company) is a diversified energy holding company
engaged primarily in the purchase, distribution, and sale of natural gas,
principally in central and north Alabama, and in the exploration, production,
acquisition and development of oil and gas in the continental United States.
The following is a description of the Company's significant accounting policies
and practices.
A. PRINCIPLES OF CONSOLIDATION
The accompanying financial statements include the accounts of the Company and
its subsidiaries, principally Alabama Gas Corporation (Alagasco) and Taurus
Exploration Inc. (Taurus), after elimination of all significant intercompany
transactions in consolidation. Certain reclassifications have been made to
conform the prior years' financial statements to the current-year presentation.
B. NATURAL GAS DISTRIBUTION
UTILITY PLANT AND DEPRECIATION: Property, plant and equipment is
stated at cost. The cost of utility plant includes an allowance for
funds used during construction. Maintenance is charged for the cost of
normal repairs and the renewal or replacement of an item of property
which is less than a retirement unit. When property which represents a
retirement unit is replaced or removed, the cost of such property is
credited to utility plant and, together with the cost of removal less
salvage, is charged to the accumulated reserve for depreciation.
Depreciation is provided on the straight-line method over the
estimated useful lives of utility property at rates established by the
Alabama Public Service Commission (APSC). Approved depreciation rates
averaged approximately 4.3 percent in 1996, 1995 and 1994. The excess
of total acquisition costs over book value of net assets acquired to
date is included in utility plant ($23.2 million, net of $6.5 in
accumulated amortization at September 30, 1996) and is being amortized
on a straight-line basis over approximately 23 years.
INVENTORIES: Inventories, which consist primarily of gas stored
underground, are stated at average cost.
OPERATING REVENUE AND GAS COSTS: In accordance with industry
practice, Alagasco records natural gas distribution revenues on a
monthly- and cycle-billing basis. The commodity cost of purchased gas
applicable to gas delivered to customers but not yet billed under the
cycle-billing method is deferred as a current asset.
REGULATORY ACCOUNTING: Alagasco is subject to the provisions of
Statement of Financial Accounting Standard (SFAS) No. 71, Accounting
for the Effects of Certain Types of Regulation. In general, SFAS No.
71 allows utilities to capitalize or defer certain costs or revenues,
based upon orders received from regulatory authorities, to be
recovered from or refunded to customers in future periods.
C. OIL AND GAS PRODUCING ACTIVITIES
PROPERTY AND RELATED DEPLETION: Taurus follows the successful efforts
method of accounting for costs incurred in the exploration and
development of oil and gas reserves. Lease acquisition costs are
capitalized initially, and unproved properties are reviewed
periodically to determine if there has been impairment of the carrying
value, with any such impairment charged to exploration expense
currently. Exploratory drilling costs are capitalized pending
determination of proved reserves. If proved reserves are not
discovered, the exploratory drilling costs are expensed. Other
exploration costs, including geological and geophysical costs, are
expensed as incurred. All development costs are capitalized.
Depreciation, depletion and amortization is determined on
field-by-field basis using the unit-of-production method based on
proved reserves. A provision for anticipated abandonment and
restoration costs at the end of a property's useful life is made
through depreciation expense.
HEDGING: Taurus periodically enters into futures contracts to hedge
its exposure to price fluctuations on oil and gas production. Gains
and losses on futures contracts are recorded in the income statement
as the hedged volumes are recognized.
36
<PAGE> 15
OPERATING REVENUE: Taurus utilizes the sales method of accounting to
recognize oil and gas production revenue. Under the sales method,
revenue is recognized for the company's total takes of oil and gas
production, and overproduction liabilities are established only when
it is estimated that a property's overproduced volumes exceed the net
share of remaining reserves for such property. The Company has no
significant production imbalances at September 30, 1996. Gains and
losses on the sale of property in the ordinary course of business are
classified as operating revenue; current year gains of $3.9 million
were recorded.
D. INCOME TAXES
The Company's deferred income taxes reflect the impact of temporary differences
between the tax basis of assets and liabilities and their carrying amounts for
financial reporting purposes and are measured in compliance with enacted tax
laws. Investment tax credits have been deferred and are being amortized over
the lives of the related assets.
E. CASH EQUIVALENTS
The Company includes highly liquid marketable securities and debt instruments
purchased with a maturity of three months or less in cash equivalents.
F. ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities at the date of the
financial statements and the reported amount of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Significant estimates with regard to these financial statements include the
estimate of proved oil and gas reserve volumes and the related present value of
estimated future net revenues therefrom (see Note 12).
2. REGULATORY MATTERS
As an Alabama utility, Alagasco is subject to regulation by the APSC which, in
1983, established the Rate Stabilization and Equalization (RSE) rate-setting
process. RSE was extended for the fourth time on October 7, 1996, for a
five-year period through January 1, 2002. Under the terms of that extension,
RSE will continue after January 1, 2002, unless, after notice to the Company
and a hearing, the Commission votes to either modify or discontinue its
operation.
Under RSE as extended, the APSC conducts quarterly reviews to determine, based
on Alagasco's projections and fiscal year-to-date performance, whether
Alagasco's return on equity for the fiscal year will be within the allowed
range of 13.15 percent to 13.65 percent. Reductions in rates can be made
quarterly to bring the projected return within the allowed range; increases,
however, are allowed only once each fiscal 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. If the change in O&M expense per
customer falls within 1.25 percentage points above or below the Consumer Price
Index For All Urban Customers (index range), no adjustment is required. If,
however, the change in O&M expense per customer exceeds the index range,
three-quarters of the difference 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. Under RSE as extended, an $8.2
million annual increase in revenue became effective December 1, 1995, and a
$1.3 million decrease in revenue became effective October 1, 1996.
Effective December 15, 1990, the APSC approved a temperature adjustment to
customers' monthly bills to remove the effect of departures from normal
temperature on Alagasco's earnings. The calculation is performed monthly, and
the adjustments to customers' bills are made in the same billing cycle the
weather variation occurs.
Alagasco's rate schedules for natural gas distribution charges contain a Gas
Supply Adjustment (GSA) rider, established in 1993, which permits the
pass-through to customers of changes in the cost of gas supply, including Gas
Supply Realignment (GSR) surcharges imposed by Alagasco's suppliers resulting
from changes in gas supply purchases related to the implementation of Federal
Energy Regulatory Commission (FERC) Order 636. On October 7, 1996, the APSC
issued an order providing for the refund to customers of approximately $17.1
million, including interest, of supplier refunds. The
37
<PAGE> 16
Order provides that refunds shall be returned to customers prior to January 31,
1997. These refunds were collected from a variety of sources and most relate to
the settlement of rate case and FERC Order 636 proceedings of Southern Natural
Gas Company (Southern) as described herein.
On September 9, 1996, the APSC approved Alagasco's application to issue $25
million of debt, a portion of which will be used to fund the supplier refunds
discussed above. On June 12, 1995, Alagasco received approval from the APSC to
issue $50 million of debt, a portion of which was used to redeem all of
Alagasco's 9 percent debentures and 11 percent First Mortgage Bonds. In
connection with the early call of the redeemed debt, Alagasco paid an early
call premium of approximately $1.3 million. Because the APSC authorized
Alagasco to collect the early call premium through customer rates, a regulatory
asset of $1.3 million was recorded at September 30, 1995, and the amounts were
collected during fiscal 1996.
In accordance with APSC-directed regulatory accounting procedures, Alagasco in
1989 began returning to customers excess utility deferred taxes which resulted
from a reduction in the federal statutory tax rate from 46 percent to 34
percent using the average rate assumption method. This method provides for the
return to ratepayers of excess deferred taxes over the lives of the related
assets. In 1993 those excess taxes were reduced as a result of a federal tax
rate increase from 34 percent to 35 percent. Remaining excess utility deferred
taxes of $2.7 million are being returned to ratepayers over approximately 14
years. At September 30, 1996 and 1995, regulatory liabilities of $5 million and
$6 million, respectively, were included in the financial statements related to
income taxes.
FERC REGULATION: On March 15, 1995, Southern filed a comprehensive settlement
with the FERC in the form of a Stipulation and Agreement (the Settlement) to
resolve all issues in Southern's six pending rate cases, as well as to resolve
all GSR and transition cost issues resulting from the implementation of FERC
Order 636. Alagasco was a supporting party to the Settlement. On April 11,
1996, the FERC issued its Order on Rehearing approving the Settlement with
minor modifications. The Settlement, as approved by FERC, provides for the
following: (1) the resolution of all cost of service and rate design issues in
Southern's six pending rate cases and the establishment of reduced rates for
the purpose of calculating rate case refunds; (2) the implementation of reduced
settlement rates for supporting parties commencing March 1, 1995; (3) the
resolution of all GSR and other transition cost issues resulting from FERC
Order 636; (4) lower GSR cost recovery through the reduction and earlier payout
of GSR costs; (5) a three-year moratorium on general rate increases; and (6)
the resolution and disposition of all rate case and GSR refunds for supporting
parties. With respect to this last point, the Settlement provides that all
rate case refunds will be used to offset a portion of Southern's remaining GSR
liability. In addition, as a result of the recalculated GSR surcharges for the
period January 1, 1994, to February 28, 1995, Southern refunded over-collected
GSR costs. As a result of this FERC order, Alagasco received other refunds
based on contracts with other suppliers whose prices were tied to Southern's
rates. In total, $17.1 million will be refunded to customers prior to January
31, 1997, and includes amounts received from Southern, other suppliers and
accrued interest.
The Settlement, as approved by FERC, resolves all issues relating to GSR and
other transition costs with respect to supporting parties. Alagasco estimates
that it has a remaining GSR liability of approximately $0.8 million to be paid
through December 1997 and approximately $1.4 million in other transition costs
to be paid through June 1998. Because these costs will be recovered in full
from its customers, Alagasco recorded regulatory assets of $2.2 million and $5
million at September 30, 1996 and 1995, respectively.
38
<PAGE> 17
3. LONG-TERM DEBT AND NOTES PAYABLE
Long-term debt consists of the following:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Energen Corporation:
Medium-term Notes, interest ranging from 7.07% to 8.09%, for notes
redeemable September 20, 2001, to September 15, 2026 ............................... $ 40,000 $ --
8% Debentures, due up to $1,000,000 annually to February 1, 2007 ..................... 18,714 18,746
Series 1993 Notes, interest ranging from 5.25% to 7.25%, due annually
in payments ranging from $805,000 to $1,604,000 from March 1, 1997,
to March 1, 2008 ..................................................................... 13,636 14,629
Alabama Gas Corporation:
Medium-term Notes, interest ranging from 5.4% to 7.97%, for notes
redeemable December 1, 1998, to September 23, 2026 ................................... 125,000 100,000
- -----------------------------------------------------------------------------------------------------------------------
Total ................................................................................... 197,350 133,375
Less amounts due within one year ....................................................... 1,805 1,775
- -----------------------------------------------------------------------------------------------------------------------
Total ................................................................................. $195,545 $131,600
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
In the prior year, the Company deposited $37.6 million into an irrevocable
trust to complete an in-substance defeasance of Alagasco's 9 percent debentures
and 11 percent Series H First Mortgage Bonds. The funds in the trust, primarily
obtained through the issuance of medium-term notes and short-term borrowings,
were used solely to satisfy the principal, interest, and call premium of the
defeased debt. Accordingly, the debt and related accrued interest were excluded
from the 1995 consolidated balance sheet. No gain or loss was recorded in the
financial statements as the APSC granted Alagasco regulatory relief related to
the income statement impact of this defeasance.
The aggregate maturities of long-term debt for the next five years are as
follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------
YEARS ENDING SEPTEMBER 30, (IN THOUSANDS)
- -------------------------------------------------------------------------------------
1997 1998 1999 2000 2001
- -------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
- -------------------------------------------------------------------------------------
$1,805 $1,855 $7,219 $1,965 $ 18,648
- -------------------------------------------------------------------------------------
</TABLE>
The Company is subject to various restrictions on the payment of dividends.
Under its 8 percent debentures, the most restrictive provision states that
dividends or other distributions with respect to common stock may not be made
unless the Company maintains a minimum consolidated tangible net worth of $80
million; at September 30, 1996, Energen had a tangible net worth of
$188,178,000.
The Company and Alagasco have short-term credit lines and other credit
facilities of $156 million available to either entity for working capital
needs. The following is a summary of information relating to notes payable to
banks:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Amount outstanding ....................................................... $ 59,000 $ 32,300 $ 6,000
Available for borrowings ................................................. 97,000 77,700 104,000
- -----------------------------------------------------------------------------------------------------------------------
Total ................................................................... $156,000 $110,000 $110,000
- -----------------------------------------------------------------------------------------------------------------------
Maximum amount outstanding at any month-end ............................... $ 95,000 $ 32,300 $ 60,000
Average daily amount outstanding ......................................... $ 37,960 $ 917 $ 13,836
Weighted average interest rates based on:
Average daily amount outstanding ....................................... 5.68% 5.76% 3.32%
Amount outstanding at year-end ......................................... 5.62% 5.96% 5.17%
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
Total interest expense for Energen in 1996, 1995 and 1994 was $13,920,000,
$11,693,000, and $11,284,000, respectively.
39
<PAGE> 18
4. INCOME TAXES
The components of income taxes consist of the following:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Taxes estimated to be payable currently:
Federal ................................................................. $5,218 $5,377 $8,550
State ................................................................... 989 873 1,369
- -----------------------------------------------------------------------------------------------------------------------
Total current ......................................................... 6,207 6,250 9,919
- -----------------------------------------------------------------------------------------------------------------------
Taxes deferred:
Federal ................................................................. (1,221) (2,580) (2,976)
State ................................................................... 62 11 (332)
- -----------------------------------------------------------------------------------------------------------------------
Total deferred ....................................................... (1,159) (2,569) (3,308)
- -----------------------------------------------------------------------------------------------------------------------
Total income tax expense ................................................. $5,048 $3,681 $6,611
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
Temporary differences and carryforwards which give rise to a significant
portion of deferred tax assets and liabilities for 1996 and 1995 are as follows:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------
AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995
- ------------------------------------------------------------------------------------------------------------------------
Current Noncurrent Current Noncurrent
---------------------------------------------
<S> <C> <C> <C> <C>
Deferred tax assets:
Regulatory liabilities ............................................. $ -- $1,872 $ -- $ 2,229
Minimum tax credit ................................................. -- 16,379 -- 14,622
Insurance and accruals ............................................. 2,487 -- 2,175 --
Unbilled revenue ................................................... 1,658 -- 1,565 --
Other, net ......................................................... 5,812 1,952 6,691 2,012
- ------------------------------------------------------------------------------------------------------------------------
Subtotal ......................................................... 9,957 20,203 10,431 18,863
Valuation allowance ............................................... -- -- -- --
- ------------------------------------------------------------------------------------------------------------------------
Total deferred tax assets ....................................... $9,957 $20,203 $10,431 $18,863
- ------------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Depreciation and basis differences ................................. $ -- $18,227 $ -- $18,497
Basis differences on oil and gas producing properties ............... -- 1,960 -- 2,160
Other, net ......................................................... 1,962 988 764 746
- ------------------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities ................................. $1,962 $21,175 $ 764 $21,403
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
No valuation allowance with respect to deferred taxes is deemed necessary as
the Company anticipates generating adequate future taxable income to realize
the benefits of all deferred tax assets on the consolidated balance sheet. As
of September 30, 1996, the amount of minimum tax credit which can be carried
forward indefinitely to reduce future regular tax liability is $16,379,000.
40
<PAGE> 19
Total income tax expense differs from the amount which would be provided by
applying the statutory federal income tax rate to earnings before taxes as
illustrated below:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Income tax expense at statutory federal income tax rate ........................... $9,306 $8,046 $10,627
Increase (decrease) resulting from:
Nonconventional fuel credits-current ........................................... (3,575) (2,343) (4,259)
Nonconventional fuel credits-deferred ........................................... (646) (1,779) 127
Investment tax credits-deferred ................................................. (487) (487) (487)
State income taxes, net of federal income tax benefit ........................... 681 625 700
Other, net ..................................................................... (231) (381) (97)
- -----------------------------------------------------------------------------------------------------------------------
Total income tax expense ......................................................... $5,048 $3,681 $ 6,611
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
5. EMPLOYEE BENEFIT PLANS
The Company has two defined benefit non-contributory pension plans which cover
a majority of the employees. Benefits are based on years of service and final
earnings. The Company's policy is to use the "projected unit credit" actuarial
method for funding and financial reporting purposes. The expense for the plan
covering the majority of employees (Plan A) for the years ended September 30,
1996, 1995 and 1994, was $412,000, $1,158,000, and $15,000, respectively. The
expense for the second plan covering employees under certain labor union
agreements (Plan B) for 1996, 1995 and 1994 was $197,000, $339,000, and
$555,000, respectively.
The funded status of the plans is as follows:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
AS OF JUNE 30, (IN THOUSANDS) PLAN A PLAN B
- -----------------------------------------------------------------------------------------------------------------------
1996 1995 1996 1995
----------------------------------------------
<S> <C> <C> <C> <C>
Vested benefits ................................................... $(56,828) $(46,073) $(14,210) $(13,499)
Nonvested benefits ............................................... (4,323) (5,912) (2,336) (2,083)
- -----------------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation ................................... (61,151) (51,985) (16,546) (15,582)
Effects of salary progression ..................................... (12,607) (11,047) -- --
- -----------------------------------------------------------------------------------------------------------------------
Projected benefit obligation ..................................... (73,758) (63,032) (16,546) (15,582)
Fair value of plan assets, primarily equity and
fixed income securities ....................................... 80,750 69,431 18,358 16,429
Unrecognized net gain (loss) ..................................... (337) 1,470 (433) 296
Unrecognized prior service cost ................................... 35 41 1,205 1,412
Unrecognized net transition obligation (asset) ................... (4,303) (5,111) 340 396
- -----------------------------------------------------------------------------------------------------------------------
Accrued pension asset ............................................. $ 2,387 $ 2,799 $ 2,924 $ 2,951
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
At September 30, 1996, for both plans the discount rate used to measure the
projected benefit obligation was 7.75 percent, and the expected long-term rate
of return on plan assets was 8.25 percent. The annual rate of salary increase
for the salaried plan was 5.75 percent. At September 30, 1995, for both plans
the discount rate used to measure the projected benefit obligation was 7.5
percent, and the expected long-term rate of return on plan assets was 8.25
percent. The annual rate of salary increase for the salaried plan was 5.5
percent.
41
<PAGE> 20
The components of net pension costs for 1996, 1995 and 1994 were:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) PLAN A PLAN B
- -----------------------------------------------------------------------------------------------------------------------
1996 1995 1994 1996 1995 1994
-----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service Cost ............................... $ 2,147 $2,052 $1,873 $ 255 $ 224 $ 224
Interest cost on projected benefit obligation 4,617 4,728 4,550 1,166 1,095 1,042
Actual (return) on plan assets ............. (22,733) (8,787) (504) (2,971) (2,172) (372)
Net amortization and deferral ............... 16,381 2,106 (5,904) 1,747 1,192 (339)
Loss due to special termination benefits ... -- 1,489 -- -- -- --
Settlement gain ............................. -- (430) -- -- -- --
- -----------------------------------------------------------------------------------------------------------------------
Net pension expense ......................... $ 412 $1,158 $ 15 $ 197 $ 339 $ 555
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
In 1995 the Company recognized a loss for special termination benefits of
$1,489,000 and a settlement gain of $430,000 pursuant to a voluntary early
retirement option offered to all salaried, non-officer employees of at least 58
years of age with a minimum of 5 years' service. Of the 55 eligible employees,
41 accepted.
The Company has deferred compensation plan agreements for certain key
executives providing for payments on retirement, termination, death or
disability. The deferred compensation expense under these agreements for 1996,
1995 and 1994 was $1,002,000, $808,000, and $461,000, respectively. At June
30, 1996 and 1995, the accumulated post-retirement benefit obligation related
to these agreements was $6,206,000 and $4,770,000, the projected benefit
obligation was $9,442,000 and $5,904,000, and the accrued post-retirement
benefit liability was $464,000 and $199,000.
In addition to providing pension benefits, the Company provides certain
post-retirement health care and life insurance benefits. Substantially all of
the Company's employees may become eligible for such benefits if they reach
normal retirement age while working for the Company. In a prior year, the
Company adopted SFAS No.106, Employers' Accounting for Post-retirement benefits
Other Than Pensions, with respect to the accrual of such costs for salaried
employees. During fiscal year 1994, the Company adopted SFAS 106 with respect
to such costs for employees under collective bargaining agreements. There was
no cumulative effect on the income statement resulting from the adoption of FAS
106, as the Company elected to amortize transition costs over a 20-year period.
On December 6, 1993, the APSC adopted an order which allows the Company to
recover all costs accrued under SFAS 106 through rates.
While the Company has not adopted a formal funding policy, all of its accrued
post-retirement liability was funded at year-end. The expense for salaried
employees for the years ended September 30, 1996, 1995, and 1994 was
$1,984,000, $2,271,000, and $2,319,000, respectively. The expense for union
employees was $4,076,000, $3,613,000, and $3,685,000 during 1996, 1995 and
1994, respectively. The "projected unit credit" actuarial method was used to
determine the normal cost and actuarial liability.
A reconciliation of the estimated status of the obligation is as follows:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
AS OF JUNE 30, (IN THOUSANDS) SALARIED EMPLOYEES UNION EMPLOYEES
- -----------------------------------------------------------------------------------------------------------------------
1996 1995 1996 1995
---------------------------------------------------
<S> <C> <C> <C> <C>
Retirees ....................................................... $(10,344) $(9,091) $(14,982) $(13,030)
Active, fully-eligible ......................................... (1,574) (3,306) (4,011) (3,776)
Other active ................................................... (7,989) (8,360) (14,415) (12,794)
- -----------------------------------------------------------------------------------------------------------------------
Accumulated post-retirement benefit obligation ................. (19,907) (20,757) (33,408) (29,600)
Fair value of plan assets, primarily equity and
fixed income securities ....................................... 17,519 12,659 8,399 4,419
Unamortized amounts ............................................. 1,210 7,550 20,887 24,237
- -----------------------------------------------------------------------------------------------------------------------
Accrued post-retirement benefit liability ....................... $ (1,178) $ (548) $ (4,122) $ (944)
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
42
<PAGE> 21
Net periodic post-retirement benefit cost for the years ended September 30,
1996, 1995, and 1994 included the following:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) SALARIED EMPLOYEES UNION EMPLOYEES
- ------------------------------------------------------------------------------------------------------------------------
1996 1995 1994 1996 1995 1994
-------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost ....................................... $ 516 $ 512 $ 450 $ 876 $ 807 $ 481
Interest cost on accumulated post-retirement
benefit obligation ............................... 1,679 1,696 1,726 2,195 1,793 1,920
Amortization of transition obligation ............... 723 723 723 1,285 1,285 1,285
Amortization of actuarial gains and losses ......... (277) -- -- -- -- --
Deferred asset (gain) loss ......................... 658 539 (453) 177 424 --
Actual (return) on plan assets ..................... (1,315) (1,199) (127) (457) (696) (1)
- ------------------------------------------------------------------------------------------------------------------------
Net periodic post-retirement benefit expense ....... $1,984 $2,271 $2,319 $4,076 $3,613 $3,685
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
The weighted average discount rate used in determining the accumulated
post-retirement benefit obligation was 7.75 percent and 7.5 percent in 1996 and
1995, respectively. The expected long-term rate of return on assets is 8.25
percent for both years, and the tax rate on investment income is assumed to be
40 percent. The weighted average health care cost trend rate used in
determining the accumulated post-retirement benefit obligation was 8 percent in
1996 and 1995. That assumption has a significant effect on the amounts
reported. For example, with respect to salaried employees, increasing the
weighted average health care cost trend rate by 1 percent would increase the
accumulated post-retirement benefit obligation by 2.4 percent and the net
periodic post-retirement benefit cost by 2.2 percent. For union employees,
increasing the weighted average health care cost trend rate by 1 percent would
increase the accumulated post-retirement benefit obligation by 7.5 percent and
the net periodic post-retirement benefit cost by 7.2 percent. The assumed
health care cost trend rate of 8 percent is not currently expected to change.
For pay-related life insurance benefits, the salary scale averages 5 percent.
For both defined benefit plans and other post-retirement plans, certain
financial assumptions are used in determining the Company's projected benefit
obligation. These assumptions are examined periodically by the Company and any
required changes are reflected in the subsequent determination of projected
benefit obligations.
The Company has a long-term disability plan covering most salaried employees.
Expense for the years ended September 30, 1996, 1995, and 1994 was $370,000,
$155,000, and $150,000, respectively.
6. COMMON STOCK PLANS
A majority of Company employees are eligible to participate in the Energen
Employee Savings Plan (ESP) by investing a portion of their compensation in the
Plan, with the Company matching a part of the employee investment by
contributing Company common stock (new issue or treasury shares) or funds for
the purchase of Company common stock. The ESP also contains employee stock
ownership plan provisions. At September 30, 1996, 352,177 common shares were
reserved for issuance under the ESP. Expense associated with Company
contributions to the ESP was $2,902,000, $2,944,000, and $2,772,000 for 1996,
1995 and 1994, respectively.
In 1992 the Company adopted the Energen Corporation 1992 Long-Range
Performance Plan which provides for the award of up to 500,000 performance
units, with each unit equal to the market value of one share of common stock,
to eligible employees based on predetermined performance criteria at the end of
a four-year award period. Under the Plan, a portion of the performance units is
payable with Company common stock; accordingly, 350,000 shares have been
reserved for issuance. Under the Plan, 62,630, 56,430, and 49,120 performance
units were awarded in 1996, 1995 and 1994, respectively, leaving 243,326
performance units available for award at September 30, 1996. The Company
recorded expense of $1,223,000, $1,628,000, and $939,000 for 1996, 1995 and
1994, respectively, under the Plan.
The Restricted Stock Incentive Plan of Energen Corporation, adopted in 1984,
provided for the award of common stock to eligible participants. Stock awarded
under the Plan is subject to certain restrictions against sale or pledge.
Pursuant to its terms, the Plan terminated effective January 1994 subject to
completion of restriction periods applicable to previously
43
<PAGE> 22
awarded shares. Under the Plan, no common shares were awarded in 1996, 1995, or
1994. Expense of $50,000, $121,000, and $218,000 was charged during 1996, 1995
and 1994, respectively, under this Plan.
In 1996, the Company amended its Dividend Reinvestment and Common Stock
Purchase Plan to include a direct stock purchase feature which allows purchases
by non-shareholders. Accordingly, 750,000 shares were added to the Plan. As of
September 30, 1996, 830,908 common shares were reserved under this Plan.
The Energen Corporation 1988 Stock Option Plan provides for the grant of
incentive stock options, non-qualified stock options, or a combination thereof
to officers and key employees. Options granted under the Plan provide for
purchase of the Company's common stock at not less than the fair market value
on the date the option is granted. Under the Plan, 270,000 shares of the
Company's common stock have been reserved for issuance. Options were granted in
1996 and 1995 with dividend equivalents. Options expire 10 years from the date
of grant. Transactions under the Plan are summarized as follows:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
AS OF SEPTEMBER 30, 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Outstanding at beginning of year ($16.75 - $20.125) ............................. 152,056 141,556 141,556
Granted (at $20.125 - $22.125) ................................................. 10,000 10,500 --
- ----------------------------------------------------------------------------------------------------------------------
Outstanding at year-end ......................................................... 162,056 152,056 141,556
- ----------------------------------------------------------------------------------------------------------------------
Exercisable at year-end ......................................................... 162,056 152,056 141,556
- ----------------------------------------------------------------------------------------------------------------------
Remaining reserved for issuance at year-end ..................................... 93,348 103,348 113,848
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
In 1992 the Company adopted the Energen Corporation 1992 Directors Stock Plan
to enable the Company to pay part of the compensation of its non-employee
directors in shares of the Company's common stock. Under the Plan, 4,322,
3,829, and 3,515 shares were issued in 1996, 1995 and 1994, respectively,
leaving 85,272 shares reserved for issuance at September 30, 1996.
The Company has adopted a Shareholder Rights Plan intended to protect
shareholders from coercive or unfair takeover tactics. Under certain
circumstances, shareholders have the right to acquire the Company's Series A
Junior Participating Preferred Stock (or, in certain cases, securities of an
acquiring person) at a significant discount. Terms and conditions are set forth
in a Rights Agreement (dated July 27, 1988, and amended February 28, 1990)
between the Company and its Rights Agent. Under the plan, two-thirds of a right
is associated with each outstanding share of Common Stock. Rights outstand-
ing under the Shareholder Rights Plan at September 30, 1996 and 1995, were
convertible into 74,418 and 72,734 shares, respectively, of Series A Junior
Participating Preferred Stock (1/100 share of preferred stock for each full
right) subject to adjustment upon the occurrence of certain take-over related
events. No rights were exercised or exercisable at either period. The price at
which the rights would be exercised is $80 per right, subject to adjustment
upon the occurrence of certain take-over related events. In general, in the
absence of certain takeover-related events, as described in the Plan, the
rights may be redeemed prior to their July 27, 1998, expiration for $0.02 per
right.
7. COMMITMENTS AND CONTINGENCIES
CONTRACTS AND AGREEMENTS: The Company has various firm gas supply and firm gas
transportation contracts which expire at various dates through the 2008. These
contracts typically contain minimum demand charge obligations on the part of
the Company.
Taurus has entered into a three-and-one-half-year agreement with Sonat
Exploration Company. Under the agreement, which extends through calendar year
1998, Taurus expects to spend between $25 and $50 million annually as its
proportionate share of acquisitions made through Sonat Exploration's reserve
acquisition program.
The Company has entered into an agreement with a financial institution whereby
it can sell on an ongoing basis, with recourse, certain installment receivables
related to its merchandising program up to a maximum of $20 million. During
1996, 1995 and 1994, the Company sold $8,831,000, $8,454,000 and $6,784,000,
respectively, of installment receivables. At
44
<PAGE> 23
September 30, 1996 and 1995, the balance of these installment receivables was
$16,964,000 and $15,618,000, respectively. Receivables sold under this
agreement are considered financial instruments with off-balance sheet risk.
The Company's exposure to credit loss in the event of non-performance by
customers is represented by the balance of installment receivables.
During 1996, Taurus entered into a sales contract covering the production from
its current year coalbed methane acquisition. The contract, in part, provides
for variable and fixed prices with fixed prices of $2.37 per Mcf and $2.02 per
Mcf for fiscal years 1997 and 1998, respectively. Taurus's net production
subject to the fixed prices is estimated at 4 Bcf per year. Taurus's gross
estimated production committed to the fixed price component of the contract
approximates 80 percent of the total anticipated production from the
acquisition during the next two fiscal years.
HEDGING: Revenues from the Company's oil and gas subsidiary are primarily the
result of sales of natural gas and oil production. Market prices of natural gas
and oil may fluctuate and significantly impact operating results. To mitigate
this risk, Taurus periodically enters into futures contracts to hedge its
exposure to price reductions on its oil and gas production. Under this program,
Taurus has entered into futures contracts for the sale of 11.5 Bcf of its
fiscal 1997 gas production at an average contract price of $2.12 per Mcf and
for the sale of 558 MBbl of its fiscal 1997 oil production at an average
contract price of $20.98 per barrel. Hedge prices do not include basis
differential.
ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight former
manufactured gas plant sites, of which it still owns four, and five
manufactured gas distribution sites, of which it still owns one. A preliminary
investigation of the sites does not indicate the present need for remediation
activities. Management expects that, should remediation of any such sites be
required in the future, Alagasco's share, if any, of such costs will not
materially affect the results of operations or financial condition of Alagasco.
Taurus is subject to various environmental regulations. Management believes
that Taurus is in compliance with the currently applicable standards of the
environmental agencies to which it is subject and that potential environmental
liabilities, if any, are minimal. Also, to the extent Taurus has operating
agreements with various joint venture partners, environmental costs, if any,
would be shared proportionately.
LEGAL MATTERS: Energen, Alagasco, and their affiliates are, from time to time,
parties to various pending or threatened legal proceedings. Certain of these
lawsuits include claims for punitive damages in addition to other specified
relief. Based upon information presently available, and in light of available
legal and other defenses, contingent liabilities arising from threatened and
pending litigation are not considered material in relation to the respective
financial positions of Energen and Alagasco. It should be noted, however, that
Energen, Alagasco and their affiliates conduct business in Alabama and other
jurisdictions in which the magnitude and frequency of punitive damage awards
bearing little or no relation to culpability or actual damages continue to rise
making it increasingly difficult to predict litigation results. Various legal
proceedings arising in the normal course of business are currently in progress
and the Company has accrued a provision for estimated costs.
CONCENTRATION OF CREDIT RISK: Natural gas distribution operating revenues and
related accounts receivable are generated from state-regulated utility natural
gas sales and transportation to more than 460,000 residential, commercial and
industrial customers located in central and north Alabama. A change in economic
conditions may affect the ability of customers to meet their obligations;
however, the Company believes that its provision for possible losses on
uncollectible accounts receivable is adequate for its credit loss exposure.
Revenues and related accounts receivable from exploration and production
operations are generated primarily from the sale of produced natural gas and
oil. This industry concentration has the potential to impact the Company's
overall exposure to credit risk, either positively or negatively, in that the
customers may be similarly affected by changes in economic, industry, or other
conditions. The Company is not aware of any significant credit risks which have
not been recognized in the provision for doubtful accounts.
45
<PAGE> 24
LEASE OBLIGATIONS: Total payments related to leases included as operating
expense in the accompanying consolidated statements of income were $3,050,000,
$3,035,000, and $2,986,000 in 1996, 1995 and 1994, respectively. Minimum future
rental payments (in thousands) required after 1996 under leases with initial or
remaining noncancelable lease terms in excess of one year are as follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------
1997 1998 1999 2000 2001 2002 and thereafter
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$3,010 $1,608 $1,109 $1,029 $ 528 $80
- -------------------------------------------------------------------------------------------------------
</TABLE>
8. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental information concerning cash flow activities is as follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest paid ........................................................... $13,261 $13,994 $11,055
Income taxes paid ....................................................... $ 5,486 $ 6,234 $10,965
Noncash investing activities:
Capitalized depreciation ............................................. $ 166 $166 $ 155
Allowance for funds used during construction ......................... $ 972 $ 1,054 $ 465
Noncash financing activities (debt issuance costs) ..................... $ 414 $ 340 $ 330
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
9. FINANCIAL INSTRUMENTS
The fair value of cash and cash equivalents, trade receivables (net of
allowance), and short-term debt approximates fair value due to the short
maturity of the instruments.
The fair value of fixed-rate long-term debt, including the current portion,
would be $194,497,000 at September 30, 1996. The fair value was based on the
market value of debt with similar maturities and with interest rates currently
trading in the marketplace.
10. RECENT PRONOUNCEMENTS OF THE FASB
In June 1995, the Financial Accounting Standards Board (FASB) issued SFAS No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of. This statement requires that long-lived assets be
reviewed for impairment whenever events or changes in the circumstances
indicate that the carrying amount for an asset may not be recoverable. The
Company is required to adopt this Statement in its 1997 fiscal year, but, based
on known facts and circumstances, does not expect implementation to have a
material impact on the Company's financial statements.
In October 1995, SFAS No. 123, Accounting for Stock-Based Compensation, was
issued and also requires adoption by the Company in its fiscal year 1997. SFAS
No. 123 establishes a fair value-based method of accounting for employee stock
options but allows companies to continue to follow the accounting treatment
prescribed by APB Opinion 25 with proper disclosure. The Company has not yet
determined the method of accounting that it will follow for stock options but
does not expect that adoption of the requirements of SFAS No. 123 will have a
material impact on the Company's financial statements.
In June 1996, SFAS No. 125, Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities, was issued and provides accounting
and reporting standards for such transactions. The Statement requires adoption
by the Company in its fiscal year 1998. Implementation of SFAS No. 125 is not
expected to have a material impact on the Company's financial statements.
46
<PAGE> 25
11. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)
The following data summarize quarterly operating results. The Company's
business is seasonal in character and strongly influenced by weather
conditions.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
1996 FISCAL QUARTERS
--------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) First Second Third Fourth
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues ............................................... $78,823 $170,987 $87,130 $62,502
Operating income (loss) ........................................... $ 4,773 $ 33,643 $ 4,011 $(3,630)
Net income (loss) ................................................. $ 2,278 $ 23,430 $ 1,071 $(5,238)
Earnings (loss) per average common share ......................... $ 0.21 $ 2.13 $ 0.10 $ (0.47)
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
1995 Fiscal Quarters
--------------------------------------------
First Second Third Fourth
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues ............................................... $72,807 $140,166 $60,954 $44,653
Operating income (loss) ........................................... $ 5,281 $ 30,237 $ 3,238 $(6,723)
Net income (loss) ................................................. $ 2,736 $ 21,714 $ 1,129 $(6,271)
Earnings (loss) per average common share ......................... $ 0.25 $ 1.99 $ 0.10 $ (0.58)
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
12. OIL AND GAS PRODUCING ACTIVITIES (Unaudited)
The following schedules detail historical financial data of the Company's oil
and gas producing activities. Certain terms appearing in the schedules are
prescribed by the Securities and Exchange Commission and are briefly described
as follows:
LEASE ACQUISITION COSTS are costs incurred to lease or otherwise acquire a
property.
EXPLORATION EXPENSES are primarily costs associated with drilling unsuccessful
exploratory wells in undeveloped properties, exploratory geological and
geophysical activities, and costs of impaired leaseholds.
DEVELOPMENT COSTS include costs necessary to gain access to, prepare and equip
development wells in areas of proved reserves.
PRODUCTION (LIFTING) COSTS include costs incurred to operate and maintain wells.
GROSS REVENUES are reported after deduction of royalty interest payments.
GROSS WELL OR ACRE is a well or acre in which a working interest is owned.
NET WELL OR ACRE is deemed to exist when the sum of fractional ownership
working interests in gross wells or acres equals one.
DRY WELL is an exploratory or a development well found to be incapable of
producing either oil or gas in sufficient quantities to justify completion as
an oil or gas well.
PRODUCTIVE WELL is an exploratory or a development well that is not a dry well.
<TABLE>
<CAPTION>
CAPITALIZED COSTS
- ----------------------------------------------------------------------------------------------------------------------
AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Proved ........................................................................... $222,428 $115,720 $90,709
Unproved ......................................................................... 2,041 1,619 1,646
- ----------------------------------------------------------------------------------------------------------------------
Total capitalized costs ......................................................... 224,469 117,339 92,355
Accumulated depreciation, depletion and amortization ............................. 60,152 51,170 43,052
- ----------------------------------------------------------------------------------------------------------------------
Capitalized costs, net ........................................................... $164,317 $66,169 $49,303
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
47
<PAGE> 26
COSTS INCURRED The following table sets forth costs incurred in property
acquisition and exploration and development activities and includes both
capitalized costs and costs charged to expense during the year:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Property acquisition:
Proved ....................................................................... $108,315 $16,950 $1,372
Unproved ..................................................................... 1,693 989 1,169
Exploration ..................................................................... 11,124 4,666 4,565
Development ..................................................................... 10,040 6,044 1,438
- ----------------------------------------------------------------------------------------------------------------------
Total costs incurred ........................................................... $131,172 $28,649 $8,544
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
RESULTS OF OPERATIONS The following table sets forth results of the Company's
oil and gas producing activities:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Gross revenues:
Unaffiliated (excluding consulting revenues) ................................. $36,706 $20,397 $21,577
Affiliated ................................................................... 1,715 2,259 2,917
Production (lifting) costs ..................................................... 10,573 5,995 5,882
Exploration expense ............................................................. 5,439 2,933 2,088
Depreciation, depletion and amortization ....................................... 18,583 8,847 8,080
Income tax benefit ............................................................. (3,004) (2,410) (1,607)
- -----------------------------------------------------------------------------------------------------------------------
Results of operations from producing activities ................................. $ 6,830 $ 7,291 $10,051
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Average sales price:
Gas (per Mcf) ................................................................. $ 1.97 $ 1.72 $ 1.89
Oil (per barrel) ............................................................. $16.25 $15.07 $14.25
Average production (lifting) cost (per Mcf equivalent) ......................... $ 0.66 $ 0.59 $ 0.57
Average depreciation rate (per Mcf equivalent) ................................. $ 1.15 $ 0.88 $ 0.78
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
DRILLING ACTIVITY The following table sets forth the total number of net
productive and dry exploratory and development wells drilled:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Exploratory:
Productive ................................................................... 1.1 0.9 0.6
Dry ........................................................................... 1.5 1.0 0.4
- -----------------------------------------------------------------------------------------------------------------------
Total ....................................................................... 2.6 1.9 1.0
- -----------------------------------------------------------------------------------------------------------------------
Development:
Productive ................................................................... 2.4 1.0 0.7
Dry ........................................................................... -- 0.1 --
- -----------------------------------------------------------------------------------------------------------------------
Total ....................................................................... 2.4 1.1 0.7
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
As of September 30, 1996, the Company was participating in the drilling of 1
gross well, with the Company's interest equivalent to .33 wells.
48
<PAGE> 27
PRODUCTIVE WELLS AND ACREAGE The following table sets forth the total gross
and net productive gas and oil wells as of September 30, 1996, and developed
and undeveloped acreage as of the latest practicable date prior to year-end:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
Gross Net
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C>
Gas Wells ....................................................................... 1,247 406
Oil Wells ....................................................................... 1,548 64
Developed Acreage ............................................................... 396,487 93,400
Undeveloped Acreage ............................................................. 152,261 18,280
- -----------------------------------------------------------------------------------------------------------
</TABLE>
The Company also had a revenue interest only in an additional 236 gross wells.
There were 103 gross wells with multiple completions with the Company's
interest being an equivalent of 49.3 wells. All wells and acreage are located
in the United States, onshore and offshore, with the majority of the net
undeveloped acreage located in the Gulf Coast region.
OIL AND GAS PRODUCING ACTIVITIES The calculation of proved reserves are made
pursuant to rules prescribed by the Securities and Exchange Commission. Such
rules, in part, require that only proved categories of reserves be disclosed
and that reserves and associated values be calculated using current prices and
costs. Changes to current prices and costs might have a significant effect on
the disclosed amount of reserves and their associated values. In addition, the
estimation of reserves inherently requires the use of geologic and engineering
estimates which are subject to revision as reservoirs are produced and
developed and as additional information is learned. Accordingly, the amount of
actual future production may vary significantly from the amount of reserves
disclosed. See Note 7 for pricing information regarding the hedging activities
of the Company. The proved reserves are located in the United States, both
onshore and offshore, and are as follows:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, 1996 1995 1994
- ------------------------------------------------------------------------------------------------------------------------
Gas Oil Gas Oil Gas Oil
MMcf MBbl MMcf MBbl MMcf Mbbl
------------------ ------------------- -----------------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves at beginning of year ............... 71,267 3,986 60,057 1,485 67,298 1,289
Revisions of previous estimates ..................... 502 369 (1,462) 142 (3,579) 144
Purchase of minerals in place ....................... 155,647 3,805 11,919 2,472 456 201
Discoveries and other additions ..................... 5,113 49 9,350 137 5,051 42
Production ......................................... (12,308) (635) (8,597) (250) (9,169) (191)
Sales of minerals in place ......................... (7,244) (1,259) -- -- -- --
- ------------------------------------------------------------------------------------------------------------------------
Proved reserves at end of year ..................... 212,977 6,315 71,267 3,986 60,057 1,485
- ------------------------------------------------------------------------------------------------------------------------
Proved developed reserves at end of year ........... 175,124 5,012 50,657 3,380 45,538 1,281
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
During the year, Taurus invested $108 million in property acquisitions and
added 178 Bcfe of proved reserves. Additional development expenditures are
required. Also, Taurus sold approximately 15 Bcfe and recorded a pre-tax gain
of $3.9 million.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES The standardized measure of discounted future net cash flows
is not intended, nor should it be interpreted, to present the fair market value
of the Company's crude oil and natural gas reserves. An estimate of fair market
value would take into consideration factors such as, but not limited to, the
recovery of reserves not presently classified as proved reserves, anticipated
future changes in prices and costs, and a discount factor more representative
of the time value of money and the risks inherent in reserve estimates.
49
<PAGE> 28
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Future gross revenues ......................................................... $502,607 $156,367 $105,986
Future production costs ....................................................... 216,755 63,311 41,113
Future development costs ..................................................... 40,665 19,029 13,024
- ------------------------------------------------------------------------------------------------------------------------
Future net cash flows before income taxes ..................................... 245,187 74,027 51,849
Future income tax expense (benefit) including tax credits ..................... 3,707 (10,533) (15,856)
- ------------------------------------------------------------------------------------------------------------------------
Future net cash flows after income taxes ..................................... 241,480 84,560 67,705
Discount at 10% per annum ..................................................... 70,641 21,001 16,051
- ------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves ..................................... $170,839 $ 63,559 $ 51,654
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
The following are the principal sources of changes in the standardized measure
of discounted future net cash flows:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at beginning of year ................................................. $ 63,559 $51,654 $72,784
- ------------------------------------------------------------------------------------------------------------------------
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future
development costs ......................................................... 15,051 (1,984) (24,969)
Net changes due to revisions in quantity estimates ......................... 552 (2,474) (2,278)
Development costs incurred, previously estimated ........................... 6,713 3,207 1,723
Accretion of discount ....................................................... 6,356 5,166 7,278
Other ....................................................................... 1,215 (37) (560)
- ------------------------------------------------------------------------------------------------------------------------
Total Revisions ............................................................... 29,887 3,878 (18,806)
New field discoveries and extensions, net of future
production and development costs ........................................... 4,705 6,021 523
Sales of oil and gas produced, net of production costs ....................... (24,002) (12,518) (14,635)
Purchases of minerals in place ............................................... 94,728 13,894 1,354
Sales of minerals in place ................................................... (10,597) -- --
Net change in income taxes ................................................... 12,559 630 10,434
- ------------------------------------------------------------------------------------------------------------------------
Net change in standardized measure of discounted future
net cash flows ............................................................. 107,280 11,905 (21,130)
- ------------------------------------------------------------------------------------------------------------------------
Balance at end of year ....................................................... $170,839 $63,559 $51,654
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
COALBED METHANE ACTIVITIES Taurus is actively engaged in the production of
pipeline-quality natural gas from coal (coalbed methane).The results of coalbed
methane activities have been included in the oil and gas disclosures shown
previously. Because of the significance of coalbed methane to Taurus, certain
data are separately disclosed below.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, 1996 1995 1994
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Proved reserves at beginning of year (Mmcf) ................................... 25,004 26,712 34,109
Revisions of previous estimates ............................................... 4,231 1,842 (3,687)
Purchases of minerals in place ............................................... 105,762 -- --
Discoveries and other additions ............................................... -- 159 --
Production ................................................................... (4,610) (3,709) (3,710)
- ------------------------------------------------------------------------------------------------------------------------
Proved reserves at end of year ............................................... 130,387 25,004 26,712
- ------------------------------------------------------------------------------------------------------------------------
Estimated proved reserves qualifying for tax credits (Mmcf) ................... 30,142 15,837 18,947
- ------------------------------------------------------------------------------------------------------------------------
Net capitalized costs (in thousands) ......................................... $77,708 $19,370 $21,924
- ------------------------------------------------------------------------------------------------------------------------
Gross wells in which Taurus has working and/or revenue interest ............... 825 634 657
- ------------------------------------------------------------------------------------------------------------------------
Net productive wells ......................................................... 279.1 154.4 164.2
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
50
<PAGE> 29
Production of coalbed methane from wells drilled prior to January 1, 1993,
qualifies through December 31, 2002, for federal income tax credits under
Section 29 of the Internal Revenue Code of 1986, as amended. The tax credit
currently approximates $1 per Mcf of qualifying production. Accordingly, a
significant portion of the value of proved coalbed methane reserves is
associated with this tax credit.
13. INDUSTRY SEGMENT INFORMATION
The Company is principally engaged in the purchase, distribution and sale of
natural gas in central and north Alabama and the development of oil and gas in
the continental United States. The Company also is engaged in intrastate gas
transmission services. Certain reclassifications have been made to conform the
prior year to the current year presentation.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
As of September 30, (in thousands) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues, unaffiliated customers:
Natural gas distribution $357,252 $295,967 $344,637
Oil and gas production 40,909 21,396 22,294
Other 1,281 1,217 7,572
- -----------------------------------------------------------------------------------------------------------------------
Total $399,442 $318,580 $374,503
- -----------------------------------------------------------------------------------------------------------------------
Intersegment revenues:
Natural gas distribution $ -- $ -- $ --
Oil and gas production 1,715 2,259 2,917
Other 877 1,081 1,238
- -----------------------------------------------------------------------------------------------------------------------
Total $ 2,592 $ 3,340 $ 4,155
- -----------------------------------------------------------------------------------------------------------------------
Depreciation, depletion and amortization expense:
Natural gas distribution $ 21,269 $ 19,368 $ 17,941
Oil and gas production 19,335 9,767 9,065
Other 514 421 970
- -----------------------------------------------------------------------------------------------------------------------
Total $ 41,118 $ 29,556 $ 27,976
- -----------------------------------------------------------------------------------------------------------------------
Capital expenditures:
Natural gas distribution $ 43,175 $ 42,780 $ 38,473
Oil and gas production 126,317 26,429 7,356
Other 60 951 334
- -----------------------------------------------------------------------------------------------------------------------
Total $169,552 $ 70,160 $ 46,163
- -----------------------------------------------------------------------------------------------------------------------
Identifiable assets:
Natural gas distribution $363,823 $335,267 $308,905
Oil and gas production 197,549 113,701 92,019
Other 9,599 10,116 10,390
- -----------------------------------------------------------------------------------------------------------------------
Total $570,971 $459,084 $411,314
- -----------------------------------------------------------------------------------------------------------------------
Operating income (loss) before income taxes:
Natural gas distribution $ 35,270 $ 32,513 $ 30,017
Oil and gas production 4,494 483 5,701
Other 263 236 1,014
Eliminations and corporate expenses (1,230) (1,199) (1,404)
- -----------------------------------------------------------------------------------------------------------------------
Total $ 38,797 $ 32,033 $ 35,328
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE> 30
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The accompanying consolidated financial statements and related notes of Energen
Corporation were prepared by management, which has the primary responsibility
for the integrity of the financial information therein. The statements were
prepared in conformity with generally accepted accounting principles
appropriate in the circumstances and include amounts which are based
necessarily on management's best estimates and judgments. Financial information
presented elsewhere in this report is consistent with the information in the
financial statements.
Management maintains a comprehensive system of internal accounting controls and
relies on the system to discharge its responsibility for the integrity of the
financial statements. This system provides reasonable assurance that corporate
assets are safeguarded and that transactions are recorded in such a manner as
to permit the preparation of reliable financial information. Reasonable
assurance recognizes that the cost of a system of internal accounting controls
should not exceed the related benefits. This system of internal accounting
controls is augmented by written policies and procedures, internal auditing,
and the careful selection and training of qualified personnel. As of September
30, 1996, management was aware of no material weaknesses in Energen's system of
internal accounting controls.
The consolidated financial statements have been audited by the Company's
independent certified public accountants, whose opinion is expressed elsewhere
on this page. Their audit was conducted in accordance with generally accepted
auditing standards; and, in connection therewith, they obtained an
understanding of the Company's system of internal accounting controls and
conducted such tests and related procedures as they deemed necessary to arrive
at an opinion on the fairness of presentation of the consolidated financial
statements.
The functioning of the accounting system and related internal accounting
controls is under the general oversight of the Audit Committee of the Board of
Directors, which is comprised of four outside Directors. The Audit Committee
meets regularly with the independent public accountants and representatives of
management to discuss matters regarding internal accounting controls, auditing
and financial reporting.
/s/ Geoffrey C. Ketcham
- -----------------------
Geoffrey C. Ketcham
Executive Vice President,
Chief Financial Officer and Treasurer
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
TO THE SHAREHOLDERS OF ENERGEN:
We have audited the accompanying consolidated balance sheets of Energen
Corporation and Subsidiaries as of September 30, 1996 and 1995, and the related
consolidated statements of income, shareholders' equity and cash flows for each
of the three years in the period ended September 30, 1996. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Energen
Corporation and Subsidiaries as of September 30, 1996 and 1995, and the
consolidated results of their operations and cash flows for each of the three
years in the period ended September 30, 1996, in conformity with generally
accepted accounting principles.
/s/ Coopers & Lybrand L.L.P.
- ----------------------------
Coopers & Lybrand L.L.P.
Birmingham, Alabama
October 23, 1996
52
<PAGE> 31
10-YEAR GRAPHS
NET INCOME CAPITALIZATION
Dollars in millions Dollars in millions
[GRAPH] [GRAPH]
TOTAL ASSETS PROPERTY, PLANT AND EQUIPMENT, NET
Dollars in millions Dollars in millions
[GRAPH] [GRAPH]
RETURN ON AVERAGE EQUITY CAPITAL EXPENDITURES
Percent Dollars in millions
[GRAPH] [GRAPH]
53
<PAGE> 32
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
ENERGEN CORPORATION AND SUBSIDIARIES
- ---------------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30,
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1996 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
INCOME STATEMENT
Operating revenues ............................................. $399,442 $318,580 $374,503 $355,878
Income before cumulative effect of change
in accounting principle ....................................... $ 21,541 $ 19,308 $ 23,751 $ 18,081
Net income ..................................................... $ 21,541 $ 19,308 $ 23,751 $ 18,081
Earnings per share before cumulative effect ..................... $1.95 $ 1.77 $ 2.19 $ 1.77
Earnings per average common share ............................... $1.95 $ 1.77 $ 2.19 $ 1.77
- ---------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET
Capitalization at year-end:
Common shareholder's equity ................................... $188,405 $173,924 $167,026 $140,313
Preferred stock ............................................... -- -- -- --
Long-term debt ............................................... 195,545 131,600 118,302 85,852
- ---------------------------------------------------------------------------------------------------------------------------
Total capitalization ....................................... $383,950 $305,524 $285,328 $226,165
- ---------------------------------------------------------------------------------------------------------------------------
Total assets ................................................... $570,971 $459,084 $411,314 $ 70,685
- ---------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment, net ............................. $444,916 $327,264 $287,182 $273,097
- ---------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA
Annual dividend rate at year-end ............................... $ 1.20 $ 1.16 $ 1.12 $ 1.08
Cash dividends paid per common share ........................... $ 1.17 $ 1.13 $ 1.09 $ 1.05
Book value per common share ..................................... $ 16.88 $ 15.94 $ 15.30 $ 13.60
Market-to-book ratio at year-end (%) ........................... 142 136 147 182
Yield at year-end (%) ........................................... 5.0 5.3 5.0 4.4
Return on average common equity (%) ............................. 11.6 11.0 14.6 13.0
Price-to-earnings ratio at year-end ............................. 12.3 12.3 10.3 14.0
Shares outstanding at year-end (000) ........................... 11,163 10,910 10,918 10,320
Price Range:
High ......................................................... $ 25 3/8 $ 23 1/2 $ 26 5/8 $ 26 3/4
Low ........................................................... $ 21 3/8 $ 19 3/4 $ 19 1/4 $ 17 5/8
Close ......................................................... $ 24 $ 21 3/4 $ 22 1/2 $ 24 3/4
- ---------------------------------------------------------------------------------------------------------------------------
OTHER GENERAL DATA
Capital expenditures ........................................... $169,552 $ 70,160 $ 46,163 $ 44,036
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
Note: All information prior to 1989 has been adjusted for the effects of a
three-for-two common stock split. All information prior to 1990
includes the effects of discontinued operations.
54
<PAGE> 33
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------
1992 1991 1990 1989 1988 1987 1986
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
$331,065 $324,902 $324,022 $308,604 $353,135 $332,590 $364,853
$ 15,687 $ 14,112 $ 11,267 $ 6,422 $ 11,667 $ 8,950 $ 1,544
$ 16,628 $ 14,112 $ 11,267 $ 6,422 $ 11,667 $ 8,950 $ 1,544
$ 1.54 $ 1.42 $ 1.15 $ .69 $ 1.53 $ 1.38 $ .24
$ 1.64 $ 1.42 $ 1.15 $ .69 $ 1.53 $ 1.38 $ .24
- --------------------------------------------------------------------------------------------------------------------------
$129,858 $121,995 $113,316 $107,950 $ 86,256 $ 63,687 $ 58,325
1,800 1,800 1,800 2,450 2,450 2,850 3,000
90,609 77,677 82,835 86,188 53,203 54,589 42,286
- --------------------------------------------------------------------------------------------------------------------------
$222,267 $201,472 $197,951 $196,588 $141,909 $121,126 $103,611
- --------------------------------------------------------------------------------------------------------------------------
$342,119 $337,516 $326,350 $294,614 $260,560 $237,445 $211,055
- --------------------------------------------------------------------------------------------------------------------------
$254,630 $273,539 $250,983 $238,329 $206,230 $191,099 $170,952
- --------------------------------------------------------------------------------------------------------------------------
$ 1.04 $ 1.00 $ .94 $ .88 $ .827 $ .76 $ .72
$ 1.01 $ .955 $ .895 $ .843 $ .777 $ .73 $ .70
$ 12.75 $ 12.07 $ 11.48 $ 11.13 $ 10.80 $ 9.73 $ 9.02
142 150 157 190 147 163 140
5.7 5.5 5.2 4.2 5.2 4.8 5.7
13.0 11.6 10.0 6.0 15.6 14.7 2.6
11.1 12.8 15.7 30.6 10.4 11.5 52.6
10,183 10,104 9,872 9,695 7,989 6,544 6,467
$ 18 7/8 $ 20 $ 21 1/2 $ 24 3/8 $ 16 1/4 $ 16 1/2 $ 14 3/8
$ 15 $ 16 $ 16 $ 15 3/8 $ 11 3/8 $ 12 1/2 $ 9
$ 18 1/8 $ 18 1/8 $ 18 $ 21 3/8 $ 15 7/8 $ 15 7/8 $ 12 5/8
- --------------------------------------------------------------------------------------------------------------------------
$ 22,758 $ 47,024 $ 37,335 $ 54,474 $ 39,260 $ 40,139 $ 39,688
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
55
<PAGE> 34
SELECTED OPERATING DATA
<TABLE>
<CAPTION>
ENERGEN CORPORATION AND SUBSIDIARIES
- -----------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30,
(DOLLARS IN THOUSANDS) 1996 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
NATURAL GAS DISTRIBUTION
Gas sold and transported (MMcf)
Residential ..................................................... 34,963 27,489 31,254 30,957
Commercial and industrial-small ................................. 14,972 12,289 13,536 13,853
Commercial and industrial-large ................................. 30 29 106 282
Transportation ................................................. 61,458 61,640 52,635 49,346
- -----------------------------------------------------------------------------------------------------------------------
Total ......................................................... 111,423 101,447 97,531 94,438
- -----------------------------------------------------------------------------------------------------------------------
Revenues from gas sold and transported
Residential ..................................................... $236,583 $194,089 $229,019 $216,587
Commercial and industrial-small ................................. 87,243 68,409 84,443 83,069
Commercial and industrial-large ................................. 669 290 790 1,223
Transportation ................................................. 30,408 30,490 29,321 27,382
Other ........................................................... 2,349 2,687 1,064 2,299
- -----------------------------------------------------------------------------------------------------------------------
Total ......................................................... $357,252 $295,965 $344,637 $330,560
- -----------------------------------------------------------------------------------------------------------------------
Average number of customers
Residential ..................................................... 418,486 410,515 402,531 395,057
Commercial and industrial-small ................................. 34,028 33,115 32,563 32,269
Commercial and industrial-large ................................. 54 48 43 46
- -----------------------------------------------------------------------------------------------------------------------
Total ......................................................... 452,568 443,678 435,137 427,372
- -----------------------------------------------------------------------------------------------------------------------
Degree days (systemwide)
39 year moving average ......................................... 2,590 2,590 2,590 2,590
Actual for year ................................................. 2,933 2,101 2,636 2,624
Ratio of actual to 39-year average (%) ......................... 1.13 .81 101.8 101.3
- -----------------------------------------------------------------------------------------------------------------------
OIL AND GAS PRODUCTION
Operating revenues ............................................... $ 42,624 $ 23,655 $ 25,211 $ 19,887
Coalbed methane proved reserves (Mmcf) ........................... 130,387 25,004 26,712 34,109
Conventional proved reserves (Mmcf)* ............................. 120,480 70,179 42,261 40,923
Oil and gas produced (Mmcf)* ..................................... 16,118 10,096 10,316 7,468
- -----------------------------------------------------------------------------------------------------------------------
OTHER ACTIVITIES
Operating revenues ............................................... $ 2,158 $ 2,298 $ 8,810 $ 10,320
Operating income ................................................. $ 263 $ 236 $ 1,014 $ 581
Property, plant and equipment, net ............................... $ 1,839 $ 2,339 $ 1,977 $ 6,273
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
* Oil expressed in natural gas equivalents
56
<PAGE> 35
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
1992 1991 1990 1989 1988 1987 1986
-------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
29,119 26,262 28,653 27,210 28,636 27,365 25,373
13,860 14,837 16,581 17,946 21,806 18,482 22,337
2,654 3,411 4,786 9,494 13,026 8,902 20,877
46,235 41,447 39,117 34,447 28,730 26,895 6,636
-------------------------------------------------------------------------------------------------------------------
91,868 85,957 89,137 89,097 92,198 81,644 75,223
-------------------------------------------------------------------------------------------------------------------
$198,676 $195,250 $188,168 $170,302 $190,836 $181,007 $165,160
78,799 84,260 85,588 85,477 104,420 93,242 112,580
6,501 8,916 13,596 25,000 37,923 24,982 77,989
25,089 22,890 22,734 19,574 15,158 17,871 3,748
1,661 (2,188) 873 731 689 679 648
-------------------------------------------------------------------------------------------------------------------
$310,726 $309,128 $310,959 $301,084 $349,026 $317,781 $360,125
-------------------------------------------------------------------------------------------------------------------
387,871 382,747 379,362 365,572 358,872 350,712 341,406
31,732 31,432 31,565 30,492 29,717 29,007 28,318
41 39 42 42 37 34 32
-------------------------------------------------------------------------------------------------------------------
419,644 414,218 410,969 396,106 388,626 379,753 369,756
-------------------------------------------------------------------------------------------------------------------
2,590 2,590 2,590 2,585 2,585 2,585 2,585
2,434 2,017 2,378 2,383 2,592 2,523 2,345
94.0 77.9 91.8 92.2 100.3 97.6 90.7
-------------------------------------------------------------------------------------------------------------------
$ 15,718 $ 12,661 $ 12,983 $ 13,469 $ 13,034 $ 9,536 $ 8,163
34,306 61,314 44,881 17,384 8,783 9,450 3,594
19,041 14,369 14,626 14,060 7,772 8,985 10,796
7,287 6,455 5,434 5,534 5,540 3,975 2,926
-------------------------------------------------------------------------------------------------------------------
$ 10,953 $ 10,900 $ 10,776 $ 5,962 $ 3,345 $ 3,843 $ 734
$ 1,764 $ 1,348 $ 1,809 $ (94) $ 1,324 $ 1,690 $ 319
$ 6,797 $ 7,098 $ 7,754 $ 9,004 $ 9,814 $ 5,833 $ 5,581
-------------------------------------------------------------------------------------------------------------------
</TABLE>
57
<PAGE> 36
GLOSSARY
BASIS DIFFERENTIAL: The difference between the futures price for a commodity
and the corresponding cash or spot price. The differential commonly is related
to differences in factors such as product quality, location and contract
pricing.
BYPASS: Obtaining service from a new gas supplier without utilizing the
facility of the former supplier.
DEVELOPMENT COSTS: Costs necessary to gain access to, prepare and equip
wells drilled to produce proved oil and gas reserves following discovery.
EXPLORATORY WELL: A well drilled to a previously untested geologic structure
to determine the presence of oil or gas.
FEDERAL ENERGY REGULATORY COMMISSION (FERC): The federal agency that, among
other functions, regulates all interstate natural gas pipelines and some
intrastate gas operations.
FUTURES CONTRACTS: Contracts that obligate the seller to deliver and the buyer
to purchase a commodity at a fixed price at a specific date.
HEDGING: The process of reducing financial exposure to adverse natural gas,
oil or other commodity price movements.
MUNICIPAL GAS SYSTEM: A natural gas distribution system owned and operated by
one or more local governments.
OPERATOR (OF OIL AND GAS PROPERTIES): The company responsible for exploration
and production activities for a specific project.
RATE STABILIZATION AND EQUALIZATION (RSE): A rate-setting mechanism authorized
by the Alabama Public Service Commission which provides Alagasco, and some
other utilities in Alabama, with the opportunity to earn a return on average
equity within a designated range.
RESERVES, OIL AND GAS: The amount of commercially recoverable oil or gas
estimated to exist within a given reservoir.
THROUGHPUT: Total volumes of natural gas sold and transported.
TRANSPORTATION OR TRANSPORT: Moving natural gas through company pipelines on a
contract basis for others.
UNITS OF MEASURE:
Mcf -- Thousand cubic feet
MMcf -- Million cubic feet
Bcf -- Billion cubic feet
(When an "e" follows these units of measure, the oil component has been
converted to its equivalent in cubic feet, with one barrel of oil equal to
6,000 cubic feet of gas.)
WORKING INTEREST: The cost-bearing ownership interest under an oil and gas
lease.
58
<PAGE> 1
EXHIBIT 21
SUBSIDIARIES OF ENERGEN CORPORATION
Alabama Gas Corporation
Taurus Exploration, Inc.
Taurus Exploration USA, Inc.
Basin Pipeline Corp
American Heat Tech, Inc.
EGN Services, Inc.
Midtown NGV, Inc.
<PAGE> 1
EXHIBIT 23
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We consent to the incorporation by reference in the registration statements of
Energen Corporation on Forms S-8 and S-3 (File No. 2-89855), Form S-3 (File
No. 333-00395), Form S-3 (File No. 333-11239) and Forms S-8 (File No. 33-27869,
File No. 33-46641, File No. 33-48504, and File No. 33-48505) of our report,
dated October 23, 1996, on our audits of the consolidated financial statements
of Energen Corporation as of September 30, 1996 and 1995, and for the years
ended September 30, 1996, 1995, and 1994, which report is incorporated by
reference in this Annual Report on Form 10-K.
Coopers & Lybrand L.L.P.
Birmingham, Alabama
December 19, 1996
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE FORM 10K
FOR SEPTEMBER 30, 1996, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000277595
<NAME> ENERGEN CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1996
<PERIOD-START> OCT-01-1995
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 276,533
<OTHER-PROPERTY-AND-INVEST> 168,383
<TOTAL-CURRENT-ASSETS> 115,295
<TOTAL-DEFERRED-CHARGES> 10,760
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 570,971
<COMMON> 112
<CAPITAL-SURPLUS-PAID-IN> 89,635
<RETAINED-EARNINGS> 98,658
<TOTAL-COMMON-STOCKHOLDERS-EQ> 188,405
0
0
<LONG-TERM-DEBT-NET> 195,545
<SHORT-TERM-NOTES> 59,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 1,805
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 126,216
<TOT-CAPITALIZATION-AND-LIAB> 570,971
<GROSS-OPERATING-REVENUE> 399,442
<INCOME-TAX-EXPENSE> 5,048
<OTHER-OPERATING-EXPENSES> 360,645
<TOTAL-OPERATING-EXPENSES> 365,693
<OPERATING-INCOME-LOSS> 33,749
<OTHER-INCOME-NET> 1,712
<INCOME-BEFORE-INTEREST-EXPEN> 35,461
<TOTAL-INTEREST-EXPENSE> 13,920
<NET-INCOME> 21,541
0
<EARNINGS-AVAILABLE-FOR-COMM> 21,541
<COMMON-STOCK-DIVIDENDS> 12,903
<TOTAL-INTEREST-ON-BONDS> 9,890
<CASH-FLOW-OPERATIONS> 52,457
<EPS-PRIMARY> 1.95
<EPS-DILUTED> 1.95
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE FORM 10K
FOR SEPTEMBER 1996, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000003146
<NAME> ALABAMA GAS CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1996
<PERIOD-START> OCT-01-1995
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 276,533
<OTHER-PROPERTY-AND-INVEST> 394
<TOTAL-CURRENT-ASSETS> 90,012
<TOTAL-DEFERRED-CHARGES> 7,467
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 374,406
<COMMON> 20
<CAPITAL-SURPLUS-PAID-IN> 34,484
<RETAINED-EARNINGS> 95,044
<TOTAL-COMMON-STOCKHOLDERS-EQ> 129,548
0
0
<LONG-TERM-DEBT-NET> 125,000
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 119,858
<TOT-CAPITALIZATION-AND-LIAB> 374,406
<GROSS-OPERATING-REVENUE> 357,252
<INCOME-TAX-EXPENSE> 9,047
<OTHER-OPERATING-EXPENSES> 321,982
<TOTAL-OPERATING-EXPENSES> 331,029
<OPERATING-INCOME-LOSS> 26,223
<OTHER-INCOME-NET> 323
<INCOME-BEFORE-INTEREST-EXPEN> 26,546
<TOTAL-INTEREST-EXPENSE> 9,585
<NET-INCOME> 16,961
0
<EARNINGS-AVAILABLE-FOR-COMM> 16,961
<COMMON-STOCK-DIVIDENDS> 9,555
<TOTAL-INTEREST-ON-BONDS> 7,390
<CASH-FLOW-OPERATIONS> 34,333
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1>EARNINGS PER SHARE IS CALCULATED FOR ENERGEN CORPORATION (PARENT COMPANY OF
ALAGASCO) AND IS NOT CALCULATED FOR ALAGASCO SEPARATELY AS AMOUNT WOULD NOT BE
MEANINGFUL.
</FN>
</TABLE>
