<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 fiscal year 2000 totaled $53 million,
or $1.75 per diluted share. This reflects a 26.8 percent increase in earnings
per diluted share (EPS) over prior-year net income of $41.4 million, or $1.38
per diluted share. The continued financial and operating strength of Energen's
utility subsidiary, Alabama Gas Corporation (Alagasco), combined with a
significant increase in the financial performance of Energen Resources
Corporation, Energen's oil and gas subsidiary, resulted in both lines of
business contributing record earnings to consolidated net income. In fiscal
year 1998, Energen reported earnings of $36.2 million, or $1.23 per diluted
share.
2000 VS 1999: Alagasco's earnings were $26.3 million, a 13 percent increase
over prior-year earnings of $23.3 million. This growth in income primarily
reflects the utility's ability to earn within its allowed range of return on an
increased level of equity representing investment in utility plant. Alagasco
achieved a return on equity (ROE) of 13.4 percent.
Energen Resources' net income in fiscal 2000 rose 58.5 percent to $27.4
million, primarily due to a 23.6 percent growth in realized sales prices for
natural gas, oil and natural gas liquids. The significantly higher realized
commodity prices more than compensated for reduced production levels primarily
resulting from prior-year property sales. Net income was affected negatively in
the third quarter by a one-time $2.2 million (7 cents per diluted share)
after-tax writedown under Statement of Financial Accounting Standards (SFAS)
No. 121 of certain oil and gas properties resulting from a downward reserve
revision. Prior-period earnings included a $2.1 million (7 cents per diluted
share) after-tax gain on the June 1999 sale of certain offshore Gulf of Mexico
properties.
1999 VS 1998: Alagasco's 1999 net income of $23.3 million increased 13.2
percent over 1998 earnings of $20.6 million, reflecting the utility's ability
to earn within its allowed range of return on an increased level of equity.
Energen Resources' net income rose $2 million to $17.3 million in fiscal 1999,
primarily due to a 35 percent increase in production volumes to 77.2 Bcfe and a
net $1 million increase in gains on property sales during the year, including
the disposition of the offshore Gulf of Mexico properties discussed above.
Partially offsetting these gains was a 20 percent decrease in realized oil
prices and increased interest expense associated with current- and prior-year
property acquisitions. In addition, Energen Resources' 1998 results were
affected negatively by a $3 million after-tax writedown of certain offshore oil
and gas properties under SFAS No. 121.
OPERATING INCOME
Consolidated operating income in 2000, 1999 and 1998 totaled $95.8 million,
$77.4 million and $61.5 million, respectively. This significant growth in
operating income was influenced by continued improvement in financial
performance from Energen Resources under Energen's diversified growth strategy,
implemented in fiscal 1996. Alagasco also has contributed to this growth in
operating income consistent with the increase in the level of equity upon which
it has been able to earn a return between 13.15 percent and 13.65 percent.
ALAGASCO: As discussed more fully in Note 2 to the Consolidated Financial
Statements, Alagasco is subject to regulation by the Alabama Public Service
Commission (APSC). On October 7, 1996, the APSC issued an order to extend
Alagasco's rate-setting mechanism, Rate Stabilization and Equalization (RSE),
through January 1, 2002. Under terms of the extension, RSE will continue after
January 1, 2002, unless, after notice to the company and a hearing, the APSC
votes to either modify or discontinue its operation.
Alagasco generates revenues through the sale and transportation of natural gas.
The transportation rate does not contain an amount representing the cost of
gas, and Alagasco's rate structure allows similar margins on transportation and
sales gas. Weather can cause variations in space heating revenues, but
operating margins essentially remain unaffected due to a real-time temperature
adjustment mechanism that allows Alagasco to adjust customer bills monthly to
reflect changes in usage due to departures from normal temperatures.
Substantially all the customers to whom the adjustment applies are residential,
small commercial and small industrial.
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<PAGE> 2
Alagasco's natural gas and transportation sales revenues totaled $366.2
million, $325.6 million and $369.9 million in fiscal years 2000, 1999 and 1998,
respectively. Significantly higher commodity gas costs and weather that was
12.8 percent colder than in the prior year contributed to the increase in sales
revenue in the current fiscal year. Sales revenue in 1999 decreased due to
weather that was 27.3 percent warmer than in fiscal 1998 and to lower commodity
gas costs.
In the current fiscal year, colder weather in Alagasco's service territory
caused a 5.3 percent increase in residential sales volumes and a 3.7 percent
increase in small commercial and industrial volumes. Transportation volumes
rose 6.3 percent, primarily due to increased volumes to a power generation
facility and a large cogeneration customer. In fiscal 1999, residential sales
volumes decreased 20.4 percent primarily due to the impact of warmer weather on
throughput. Small commercial and industrial volumes, also sensitive to weather,
decreased 14.9 percent. Variance in electric peaking demand was the primary
reason for a 6 percent decrease in transportation volumes.
Higher commodity cost of gas and increased purchased volumes resulting from
colder weather in fiscal 2000 generated a 23.4 percent increase in cost of gas.
In fiscal 1999, warmer weather had the opposite impact on purchased volumes
and, combined with a lower commodity cost, generated a 28.3 percent decrease in
cost of gas.
Operations and maintenance (O&M) expense at the utility increased 3.7 percent
in fiscal 2000 primarily due to higher labor and related costs partially offset
by reduced bad debt and general liability insurance expense. In the prior year,
O&M expense increased 1.6 percent primarily due to increased costs for Year
2000-related (Y2K) expenses and increased bad debt expense resulting from
colder weather in 1998 and increased exposure from a large industrial customer;
reduced insurance costs partially offset these increases. In 2000 and in 1998,
the increase in O&M expense on a per-customer basis fell within the
inflation-based Cost Control Measurement (CCM) established by the APSC as part
of the utility's rate-setting mechanism. In 1999, the increase in O&M expense
per customer fell below the CCM resulting in the utility benefiting by $0.7
million pre-tax, or one-half the difference, in future rate adjustments (see
Note 2). Under the terms of RSE, Y2K costs were excluded from the O&M
inflation-based calculation.
Consistent with growth in the utility's depreciable base, depreciation expense
rose 7.4 percent in 2000 and 6.3 percent in 1999. 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.
<TABLE>
<CAPTION>
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Years ended September 30, (dollars in thousands) 2000 1999 1998
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<S> <C> <C> <C>
Natural gas transportation and sales revenues $ 366,161 $ 325,554 $ 369,940
Cost of natural gas (155,841) (126,264) (176,124)
Revenue taxes (19,749) (17,714) (20,278)
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Natural gas transportation and sales margin $ 190,571 $ 181,576 $ 173,538
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Natural gas sales volumes (MMcf)
Residential 26,069 24,751 31,079
Commercial and industrial-small 12,092 11,662 13,705
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Total natural gas sales volumes 38,161 36,413 44,784
Natural gas transportation volumes (MMcf) 70,534 66,356 70,563
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Total deliveries (MMcf) 108,695 102,769 115,347
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</TABLE>
ENERGEN RESOURCES: Revenues from oil and gas operations continued to increase
in the current fiscal year largely as a result of significantly higher
commodity prices. Realized gas prices rose 12.7 percent to $2.49 per Mcf, while
realized oil prices increased 51.9 percent to $18.11 per barrel. Natural gas
liquids prices increased 67.4 percent to an average price of $16.04 per barrel.
During 2000, total production volumes decreased 8.7 percent to 70.5 Bcfe
primarily due to the offshore property sales occurring in the latter half of
fiscal 1999. Natural gas production decreased 10.7 percent to 48.1 Bcf and oil
volumes declined 26.2 percent to 2,304 MBbl. Production of natural gas liquids
increased 87.5 percent to 1,429 MBbl as a result of higher liquids prices,
which led to substantially all natural gas liquids being removed from the gas
stream during processing.
During 1999, revenues from oil and gas production grew mainly as a result of
the TOTAL Minatome Corporation (TOTAL) property acquisition and prior-year
property acquisitions. Energen Resources purchased the stock of TOTAL, a
Houston-based unit of TOTAL American Holding Inc., in October 1998. Immediately
upon closing the transaction, Energen Resources sold a 31 percent undivided
interest in TOTAL's net assets to Westport Oil and Gas Company Inc. Energen
Resources' net adjusted price totaled approximately $137.5 million, including
the assumption of certain legal and financial obligations. Energen Resources
gained an estimated 200 Bcfe of proved domestic oil and natural gas reserves.
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<PAGE> 3
Energen Resources' production volumes in fiscal year 1999 rose 34.5 percent to
77.2 Bcfe. Natural gas production increased 22.8 percent to 53.9 Bcf. Oil
volumes more than doubled to 3,122 MBbl, while natural gas reserves yielded 762
MBbl in natural gas liquids for the year, a decrease from 1998 of 6.7 percent.
Realized gas prices remained constant at $2.21 per Mcf, while realized oil
prices declined 20.3 percent to $11.92 per barrel. Natural gas liquids prices
increased 10.8 percent to an average price of $9.58 per barrel.
Coalbed methane operating fees are calculated as a percentage of net proceeds
on certain properties, as defined by the related operating agreements, and vary
with changes in natural gas prices, production volumes and operating expenses.
Revenues from operating fees were $4.3 million, $3.9 million and $4.3 million
in 2000, 1999 and 1998, respectively.
Energen Resources may, in the ordinary course of business, be involved in the
sale of developed and undeveloped properties. With respect to developed
properties, sales may occur as a result of, but not limited to, disposing of
non-strategic or marginal assets and accepting offers where the buyer gives
greater value to a property than does Energen Resources. In 2000, 1999 and
1998, Energen Resources recorded in operating revenues net pre-tax gains on the
sale of various properties of $1.1 million, $4.2 million and $2.6 million,
respectively. The largest of these property sales occurred in June 1999 when
Energen Resources recorded a $3.2 million pre-tax gain on the sale of offshore
Gulf of Mexico properties.
<TABLE>
<CAPTION>
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Years ended September 30, (dollars in thousands, except sales price data)
2000 1999 1998
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<S> <C> <C> <C>
Revenues
Natural gas production $ 119,680 $ 119,021 $ 97,123
Oil production 41,745 37,227 21,452
Natural gas liquids production 22,914 7,296 7,061
Operating fees 4,262 3,932 4,342
Other 833 4,487 2,709
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Total revenues $ 189,434 $ 171,963 $ 132,687
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Production volumes
Natural gas (MMcf) 48,084 53,855 43,853
Oil (MBbl) 2,304 3,122 1,433
Natural gas liquids (MBbl) 1,429 762 817
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Average unit sales price
Natural gas (per Mcf) $ 2.49 $ 2.21 $ 2.21
Oil (per barrel) $ 18.11 $ 11.92 $ 14.96
Natural gas liquids (per barrel) $ 16.04 $ 9.58 $ 8.65
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</TABLE>
Operations expense decreased $3.4 million in 2000 and increased $20.9 million
1999. Lease operating expense decreased by $3.8 million in 2000 primarily due
to the sale of the offshore properties in the prior fiscal year. In 1999, lease
operating expense increased $20 million almost entirely due to increased
production from acquisitions. In the current fiscal year, administrative
expense increased $1 million and was higher by $2.8 million in 1999, largely
due to the acquisition of TOTAL. Exploration expense decreased $0.1 million in
2000 and $0.8 million in 1999, primarily due to decreased exploratory efforts.
DD&A decreased $3.5 million in 2000 largely due to lower production volumes
partially offset by additional pre-tax DD&A expense of $3.5 million, resulting
from a downward reserve revision on a small oil and gas field located in
Mississippi, recorded under SFAS No. 121, Accounting for the Impairment of
Long-Lived Assets and For Long-Lived Assets to Be Disposed Of (see Note 11).
Energen Resources' significantly higher production volumes generated the
majority of the $6 million increase in DD&A expense in 1999. The average
depletion rate (excluding the effect of the current-year writedown) was $0.76
per Mcf in 2000 as compared to $0.79 per Mcf in the prior year.
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<PAGE> 4
Energen Resources' expense for taxes other than income primarily reflected
production-related taxes. For 2000, Energen Resources recorded severance taxes
of $17.6 million, an increase largely due to commodity prices. Severance taxes
in 1999 and 1998, were $11.3 million and $9.4 million, respectively, as a
result of increased production.
NON-OPERATING ITEMS
CONSOLIDATED: Interest expense remained relatively stable and the average daily
outstanding balance under short-term credit facilities of $146.8 million
decreased $7.7 million in fiscal year 2000 primarily due to reduced
expenditures for property acquisitions. Fiscal 1999 interest expense increased
$7.2 million primarily due to the increased use of short-term credit facilities
to finance Energen Resources' acquisition of TOTAL. The average daily
outstanding balance under short-term credit facilities was $155 million in 1999
as compared to $81 million in fiscal year 1998. Also influencing interest
expense in 1999 was interest for a full year on $100 million of medium-term
notes issued in February 1998.
The Company's effective tax rates in 2000, 1999 and 1998 were lower than
statutory federal tax rates primarily due to the recognition of nonconventional
fuels tax credits and the amortization of investment tax credits.
Nonconventional fuels tax credits are generated annually on qualified
production through December 31, 2002. They are expected to be recognized fully
in the financial statements, and effective tax rates are expected to continue
to remain lower than statutory federal rates in the near future. Income tax
expense increased in 2000 and 1999 primarily due to higher pre-tax income. The
Company recognized $14.4 million, $14.8 million and $14.5 million in
nonconventional fuels tax credits in 2000, 1999 and 1998, respectively. As of
September 30, 2000, the amount of minimum tax credit that has been previously
recognized and can be carried forward indefinitely to reduce future regular tax
liability is $48.3 million.
FINANCIAL POSITION AND LIQUIDITY
The Company's net cash from operating activities totaled $105 million, $130.6
million and $123.6 million in 2000, 1999 and 1998, respectively. Operating cash
flow in the current year benefited from significantly higher realized oil, gas
and natural gas liquids prices at Energen Resources. Working capital needs at
Alagasco were affected by increased gas costs resulting in higher accounts
receivable and storage inventory balances. In fiscal 1999 and 1998, operating
cash flow benefited from significantly higher production volumes related to
Energen Resources' property acquisitions. Other working capital items, which
primarily are the result of changes in throughput and the timing of payments,
combined to create the remaining increases for all years.
During fiscal 2000, the Company made net investments of $131.7 million. Energen
Resources invested $2.4 for property acquisitions, $66.7 million for
development of proved properties and $1.2 million for exploration. Energen
Resources' successful development wells and other exploitation activities added
approximately 76 Bcfe of reserves in fiscal year 2000. Utility expenditures for
the year totaled $67.1 million and primarily represented support facilities and
normal system distribution expansion along with $13 million to replace
liquifaction equipment at one of its two liquified natural gas facilities.
During fiscal 1999, the Company made net investments of $188.1 million largely
due to the acquisition of oil and gas properties. Energen Resources invested
$144 million for property acquisitions, including $137.5 million for TOTAL,
$55.5 million for development and $1.7 million for exploration. Energen
Resources' acquisitions in 1999 added approximately 200 Bcfe of proved reserves
while its 88 successful development wells and other exploitation activities
added approximately 120 Bcfe of reserves. Utility expenditures in 1999 totaled
$46 million. The Company had cash proceeds of $56.9 million resulting from the
sale-leaseback of the headquarters building and the sale of certain offshore
and onshore properties during 1999. Cash used in investing activities was
$166.3 million in 1998. Energen Resources invested $84.7 million for proved
property acquisitions, $35.3 million for development and $3.9 million for
exploration, adding 168 Bcfe to proved reserves in 1998. Energen Resources sold
or traded certain properties during 1998, resulting in cash proceeds of $7.6
million. Utility expenditures in 1998 totaled $54.2 million.
Cash used in financing activities totaled $114.9 million in 2000 resulting
primarily from fluctuations in the amount and timing of short-term debt at
year-end. Financing activities provided a source of cash totaling $99.6 million
and $40.5 million in 1999 and 1998, respectively. Due to a change in tax law
during fiscal 2000, the Company had no borrowings at September 30, 2000, in
order to purchase short-term federal obligations for tax planning purposes as
in previous years. The Company borrowed $140.9 and $100.6 million at September
30, 1999 and 1998, respectively, to invest in short-term federal obligations
that were sold in early October with the proceeds used to repay the debt. In
1999, the Company utilized $74.7 million in short-term credit facilities to
finance Energen Resources' acquisition strategy and reduced long-term debt by
$6.2 million. In February 1998, the Company issued $100 million of long-term
debt redeemable February 15, 2028. The $98.5 million in proceeds were used to
repay short-term borrowings incurred to finance Energen Resources' growth
activities. For each of the years, net cash used in financing activities
reflected dividends paid to common stockholders and the issuance of common
stock through the dividend reinvestment and direct stock purchase plan and the
employee savings plans.
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<PAGE> 5
CAPITAL EXPENDITURES
NATURAL GAS DISTRIBUTION: During the last three fiscal years, Alagasco invested
$167.3 million for capital projects: $88.7 million on normal expansion
replacements and support of its distribution system and $78.6 million on
support facilities, including the replacement of liquifaction equipment and the
development and implementation of information systems.
<TABLE>
<CAPTION>
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Years ended September 30, (in thousands) 2000 1999 1998
------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Capital expenditures for:
Renewals, replacements, system expansion
and other $ 35,774 $ 26,095 $ 26,806
Support facilities 31,299 19,934 27,362
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Total $ 67,073 $ 46,029 $ 54,168
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</TABLE>
OIL AND GAS OPERATIONS: Energen Resources spent $400 million for capital
projects over the last three fiscal years, $13.3 million of which was charged
to income as exploration expense. Property acquisition expenditures totaled
$231.1 million; $157.5 million was spent in development activities, and
exploratory expenditures totaled $6.7 million.
<TABLE>
<CAPTION>
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Years ended September 30, (in thousands) 2000 1999 1998
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Capital and exploration expenditures for:
Property acquisitions $ 2,436 $ 143,959 $ 84,747
Development 66,717 55,487 35,307
Exploration 1,150 1,697 3,885
Other 1,343 2,150 1,117
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Total 71,646 203,293 125,056
Less exploration expenditures charged to income 4,556 4,716 4,065
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Net capital expenditures $ 67,090 $ 198,577 $ 120,991
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</TABLE>
FUTURE CAPITAL RESOURCES AND LIQUIDITY
The Company plans to continue to implement its diversified growth strategy that
focuses on expanding Energen Resources' oil and gas operations through the
acquisition and exploitation of producing properties with development potential
while building on the strength of the Company's utility foundation. The primary
objective of this strategy, adopted in fiscal year 1996, is to realize average
compound EPS growth of 10 percent a year over each rolling five-year period. In
the first five fiscal years under this strategy, Energen's EPS grew at an
average compound rate of 14.7 percent a year.
Energen's management believes the United States is in the early stages of a
multi-year period of sustained average natural gas prices in excess of $3 per
year. Such sustained natural gas prices will have a dramatic impact on
Energen's earnings and cash flows from operations. Energen's management plans
to utilize commodity price-driven increases in cash flows to help to finance
Energen Resources' acquisition and exploitation strategy and to help reduce
Energen's debt-to-total capitalization ratio to 50 percent over the next five
years. The Company will continue to utilize available short-term credit
facilities, as needed, to supplement internally generated cash flow, with
long-term debt providing permanent financing. During fiscal year 1999, Energen
increased its available short-term credit facilities to $249 million to help
accommodate its growth plans.
In fiscal year 2001, Energen Resources plans to invest approximately $125
million, including $50 million in property acquisitions and $60 million in
exploitation activities. Energen Resources' exploratory exposure in fiscal 2001
is estimated to be $6 million, along with an additional $7 million in
associated development. Capital investment at Energen Resources in fiscal year
2002, is expected to approximate $175 million for acquisitions, $42 million for
exploitation and $13 million for exploration and related development. Energen
Resources' capital investment for oil and gas activities over the five-year
period ending September 30, 2005, is estimated to range from $950 million to $1
billion. During this period, the Company expects to issue approximately $250
million in long-term debt to replace short-term obligations and to provide
permanent financing for its acquisition strategy. Energen Resources' continued
ability to invest in property acquisitions will be influenced significantly by
industry trends, as the producing property acquisition market historically has
been cyclical. From time to time, Energen Resources also may be engaged in
negotiations to sell, trade or otherwise dispose of properties.
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<PAGE> 6
During fiscal year 2001, Alagasco plans to invest approximately $57 million in
utility capital expenditures for normal distribution and support systems,
including approximately $12 million for revenue-producing main projects and $3
million for remaining replacement costs of its liquifaction equipment. Alagasco
maintains an investment in storage gas that is expected to average
approximately $36 million in 2001. Alagasco plans to invest approximately $55
million in utility capital expenditures during fiscal year 2002. The utility
anticipates funding these capital requirements through internally generated
capital and the utilization of short-term credit facilities. Over the Company's
five-year planning period ending September 30, 2005, Alagasco anticipates
capital investments of approximately $275 million and may issue $50 million in
long-term debt to replace short-term financing and supplement internally
generated cash flow.
OUTLOOK
Natural Gas Distribution: The five-year extension of RSE in October 1996
provides Alagasco the opportunity to continue earning an allowed ROE between
13.15 percent and 13.65 percent through January 1, 2002. Over this period,
Alagasco has the potential for net income growth as the investment in
additional utility plant affects the level of equity required in the business.
Alagasco's 13-month average equity is estimated to be $212.5 million and $225
million at the end of fiscal years 2001 and 2002, respectively. The utility
continues to rely on rate flexibility to effectively prevent bypass of its
distribution system. Even though the utility enjoys a market saturation rate
higher than the national average, customer growth in the service territory is
limited. In the year 2001, Alagasco will continue to focus on enhancing
customer growth by aggressively pursuing conversion opportunities.
Oil and Gas Operations: Energen Resources plans to continue to implement its
acquisition and exploitation program with capital spending in fiscal years 2001
and 2002 as outlined above. Assuming no property acquisitions are made prior to
September 30, 2001, production in fiscal 2001 is expected to be approximately
68 Bcfe. In fiscal year 2002, production is expected to increase to
approximately 81.5 Bcfe as a result of successful exploitation and of property
acquisitions assumed to take place at fiscal year-end 2001 and the fourth
quarter of 2002.
Energen Resources expects to generate approximately $13 million and $12 million
of nonconventional fuels tax credits during fiscal years 2001 and 2002,
respectively. Nonconventional fuels tax credits are generated annually on
qualified production through December 31, 2002. As the tax credit expiration
date approaches, Energen Resources plans to continue to replace the tax credits
with revenue-generating property acquisitions and related development in a
manner that does not negatively affect corporate earnings in fiscal year 2003
and beyond.
Energen Resources' major market risk exposure is in the pricing applicable to
its oil and gas production. Historically, prices received for oil and gas
production have been volatile because of seasonal weather patterns, national
supply and demand factors and general economic conditions. Crude oil prices
also are affected by quality differentials, by worldwide political developments
and by actions of the Organization of Petroleum Exporting Countries. Basis
differentials, like the underlying commodity prices, can be volatile because of
regional supply and demand factors, including seasonal variations and the
availability and price of transportation to consuming areas.
Energen Resources enters into derivative commodity instruments to hedge its
exposure to oil and gas price fluctuations. Such instruments include regulated
natural gas and crude oil futures contracts traded on the New York Mercantile
Exchange (NYMEX) and over-the-counter swaps and basis hedges with major energy
derivative product specialists. All hedge transactions are subject to the
Company's risk management policy, approved by the Board of Directors, which
does not permit speculative positions.
As of September 30, 2000, 79 percent of Energen Resources' estimated 2001 gas
production was hedged or under contract at an average NYMEX price of $2.76 per
Mcf. The Company also had hedges in place for 59 percent of its estimated 2001
oil production: 950 MBbl of its oil production at an average NYMEX price of
$24.32 per barrel, 150 MBbl of oil production with a collar price of $20.00 to
$25.24 per barrel and 150 MBbl of basin-specific hedges at an average realized
price of $23.53 per barrel. In addition, the Company had hedged the basis
difference on 17.8 Bcf of its fiscal 2001 basin-specific production. Subsequent
to September 30, 2000, Energen Resources entered into additional contracts and
swaps for fiscal year 2001, resulting in a total of 1,188 MBbl of oil
production hedged at an average NYMEX price of $25.30 per barrel. The oil
collar and basin-specific hedges remain unchanged. Contracts and swaps also are
in place for 6 Bcf of fiscal year 2002 gas production at an average NYMEX price
of $3.19. As acquisitions are made, Energen Resources may use futures, swaps
and/or fixed-price contracts to lock in commodity prices for up to 36 months in
order to protect targeted returns. Energen Resources may hedge up to 80 percent
of its estimated annual production as approved by the Company's Board of
Directors. The Company had current deferred hedging losses of $83.5 million and
$16.5 million included in prepayments and other on the consolidated balance
sheet at September 30, 2000 and 1999, respectively. The Company had non-current
deferred hedging losses of $5.9 million included in deferred charges and other
on the consolidated balance sheet at September 30, 2000. In fiscal 2001, the
Company is required to adopt SFAS No. 133, Accounting for
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<PAGE> 7
Derivative Instruments and Hedging Activities, as amended, which establishes
new accounting and reporting standards for derivatives.
In addition to the derivatives described above, the Company has three-way
pricing, physical sales contracts in place for approximately 23 percent of its
estimated gas production in fiscal year 2002. These contracts provide for
Energen Resources to receive a basin-specific weighted average price between
$2.82 and $3.94 per Mcf. If the market price falls between $2.40 and $2.82 per
Mcf, Energen Resources will receive $2.82 per Mcf. If the market price falls
below $2.40 per Mcf, Energen Resources will receive the market price plus a
premium of $0.33-$0.45, depending on the contracts. In fiscal year 2003, the
Company has three-way pricing, physical sales contracts in place for
approximately 17 percent of its estimated gas production. These contracts
provide for Energen Resources to receive a basin-specific weighted average
price between $2.72 and $3.94 per Mcf. If the market price falls between $2.40
and $2.72 per Mcf, Energen Resources will receive $2.72 per Mcf. If the market
price falls below $2.40 per Mcf, Energen Resources will receive the market
price plus a premium of $0.23-$0.35, depending on the contracts.
Energen is expected to generate EPS growth of approximately 13 percent in
fiscal year 2001. Energen's earnings estimates for fiscal year 2001 assume that
its unhedged gas production will receive an average NYMEX price of $3 per Mcf
and that the NYMEX price for its oil production will average $25 per barrel.
The price for natural gas liquids is assumed to average approximately $16.80
per barrel. In fiscal year 2001, because of our sensitivity to commodity
prices, Energen Resources' estimates that a $1 per barrel change in oil prices
from the $25 per barrel assumption, together with a corresponding change in the
price of natural gas liquids, will have an approximate $0.8 million effect on
net income. Similarly, a 10-cents per Mcf change in gas prices from the $3 per
Mcf assumption is estimated to have a $0.4 million effect on net income.
In fiscal year 2002, Energen is expected to generate EPS growth of
approximately 20 percent. Energen's earnings estimates for fiscal year 2002
assume that its unhedged gas production will receive an average NYMEX price of
$3.10 per Mcf and that the NYMEX price for its oil production will average $24
per barrel. The price for natural gas liquids is assumed to average
approximately $16.20 per barrel. In fiscal year 2002, Energen Resources'
estimates that a $1 per barrel change in oil prices from the $24 per barrel
assumption, together with a corresponding change in the price of natural gas
liquids, will have an approximate $1.9 million effect on net income. Similarly,
a 10-cents per Mcf change in gas prices from the $3.10 per Mcf assumption is
estimated to have a $2.9 million effect on net income.
The Company has prepared a sensitivity analysis to evaluate the hypothetical
effect that changes in the market value of crude oil and natural gas may have
on the fair value of its derivative instruments. This analysis measured the
impact on the commodity derivative instruments and, thereby, did not consider
the underlying exposure related to the commodity. At September 30, 2000 and
1999, the Company estimated that a 10 percent change in the underlying
commodities prices would have resulted in a $23.6 million and a $12.1 million,
respectively, change in the fair value of open derivative contracts; however,
gains and losses on derivative contracts are expected to be similarly offset by
sales at the spot market price. Due to the short duration of the contracts, the
time value of money was ignored. The hypothetical change in fair value was
calculated by multiplying the difference between the hypothetical price and the
contractual price by the contractual volumes and did not include the variance
in basis difference or the impact of related taxes on actual cash prices.
FORWARD-LOOKING STATEMENT AND RISK: Certain statements in this report, express
expectations of future plans, objectives and performance of the Company and its
subsidiaries, and constitute forward-looking statements made pursuant to the
Safe Harbor provision of the Private Securities Litigation Reform Act of 1995.
Except as otherwise disclosed, the Company's forward-looking statements do not
reflect the impact of possible or pending acquisitions, divestitures or
restructurings. We undertake no obligation to correct or update any
forward-looking statements, whether as a result of new information, future
events or otherwise. All statements based on future expectations rather than on
historical facts are forward-looking statements that are dependent on certain
events, risks and uncertainties that could cause actual results to differ
materially from those anticipated. Some of these include, but are not limited
to, economic and competitive conditions, inflation rates, legislative and
regulatory changes, financial market conditions, future business decisions, and
other uncertainties, all of which are difficult to predict. There are numerous
uncertainties inherent in estimating quantities of proved oil and gas reserves
and in projecting future rates of production and timing of development
expenditures. The total amount or timing of actual future production may vary
significantly from reserves and production estimates. In the event Energen
Resources is unable to fully invest its planned acquisition, development and
exploratory expenditures, future operating revenues, production, and proved
reserves could be negatively affected. The drilling of development and
exploratory wells can involve significant risks, including those related to
timing, success rates and cost overruns and these risks can be affected by
lease and rig availability, complex geology and other factors. Although Energen
Resources makes use of futures, swaps and fixed-price contracts to mitigate
risk, fluctuations in future oil and gas prices could affect materially the
Company's financial position and results of operation; furthermore, such risk
mitigation activities may cause the Company's financial position and results of
operations to be materially different from results that would have been
obtained had such risk mitigation activities not occurred. In addition, the
Company cannot guarantee the absence of errors in input data, calculations and
formulas used in its estimates, assumptions and forecasts.
29
<PAGE> 8
RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD
In June 1998, the FASB issued SFAS No. 133, (subsequently amended by SFAS Nos.
137 and 138), which established new accounting and reporting standards for
derivative instruments. The Company is required to adopt this statement on
October 1, 2000. This statement requires the Company to recognize all
derivatives as either assets or liabilities on the balance sheet and measure
the effectiveness of the hedges, or the degree that the gain (loss) for the
hedging instrument offsets the loss (gain) on the hedged item, at fair value
each reporting period. The effective portion of the gain or loss on the
derivative instrument will be recognized in other comprehensive income as a
component of equity until the hedged item is recognized in earnings. The
ineffective portion of the derivative's change in fair value is required to be
recognized in earnings immediately. During the Company's implementation
process, management has identified oil and gas derivatives which qualify as
cash flow hedges. Unrealized gains and losses resulting from changes in the
fair value of the effective portion of the derivatives will be reported
directly to shareholders' equity. Effective October 1, 2000, the Company
reclassified deferred hedging losses included in the consolidated balance sheet
at September 30, 2000, to other comprehensive loss reflected as a reduction of
equity in accordance with SFAS No. 133 in the amount of $55.4 million, net of
tax. While certain derivatives not qualifying for hedge accounting will
directly impact reported net income and have potential earnings volatility to
the Company, management does not believe the adoption of SFAS No. 133 will have
a material impact on the results of operations of the Company.
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, 1997 20.63 17.31 19.88 .155
March 31, 1998 22.00 18.38 22.00 .155
June 30, 1998 22.50 19.00 20.13 .155
September 30, 1998 20.75 15.13 19.00 .160
---------------------------------------------------------------------------------------------------------------------------------
December 31, 1998 19.50 17.44 19.50 .160
March 31, 1999 19.75 13.13 14.94 .160
June 30, 1999 19.94 14.50 18.63 .160
September 30, 1999 20.38 17.50 20.25 .165
---------------------------------------------------------------------------------------------------------------------------------
December 31, 1999 21.25 15.75 18.06 .165
March 31, 2000 18.94 14.69 15.94 .165
June 30, 2000 23.69 16.00 21.81 .165
September 30, 2000 30.38 21.00 29.75 .170
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
* Share prices reflect a 2-for-1 stock split effective March 2, 1998.
30
<PAGE> 9
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Energen Corporation
----------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, (in thousands, except share data) 2000 1999 1998
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Natural gas distribution $ 366,161 $ 325,554 $ 369,940
Oil and gas operations 189,434 171,963 132,687
----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 555,595 497,517 502,627
----------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas 154,201 124,379 174,051
Operations and maintenance 171,636 169,874 148,376
Depreciation, depletion and amortization 87,073 88,615 80,999
Taxes, other than income taxes 46,884 37,266 37,716
----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 459,794 420,134 441,142
----------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 95,801 77,383 61,485
----------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense (37,769) (37,173) (30,001)
Other, net 1,775 1,335 2,544
----------------------------------------------------------------------------------------------------------------------------------
Total other expense (35,994) (35,838) (27,457)
----------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 59,807 41,545 34,028
Income tax expense (benefit) 6,789 135 (2,221)
----------------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 53,018 $ 41,410 $ 36,249
----------------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER AVERAGE COMMON SHARE $ 1.75 $ 1.38 $ 1.23
----------------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS PER AVERAGE COMMON SHARE $ 1.76 $ 1.40 $ 1.25
----------------------------------------------------------------------------------------------------------------------------------
DILUTED AVERAGE COMMON SHARES OUTSTANDING 30,359,417 29,920,681 29,437,987
----------------------------------------------------------------------------------------------------------------------------------
BASIC AVERAGE COMMON SHARES OUTSTANDING 30,108,149 29,643,610 29,083,855
----------------------------------------------------------------------------------------------------------------------------------
</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
----------------------------------------------------------------------------------------------------------
As of September 30, (in thousands) 2000 1999
----------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 3,823 $ 145,390
Accounts receivable, net of allowance for doubtful accounts of
$6,681 in 2000 and $5,598 in 1999 93,362 74,505
Inventories, at average cost
Storage gas inventory 36,437 24,722
Materials and supplies 8,535 8,287
Liquified natural gas in storage 3,267 3,318
Deferred income taxes 17,830 14,691
Prepayments and other 92,182 24,834
----------------------------------------------------------------------------------------------------------
Total current assets 255,436 295,747
----------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, successful efforts method 713,766 669,985
Less accumulated depreciation, depletion and amortization 165,447 129,839
----------------------------------------------------------------------------------------------------------
Oil and gas properties, net 548,319 540,146
----------------------------------------------------------------------------------------------------------
Utility plant 709,004 645,596
Less accumulated depreciation 353,997 328,775
----------------------------------------------------------------------------------------------------------
Utility plant, net 355,007 316,821
----------------------------------------------------------------------------------------------------------
Other property, net 4,503 4,140
----------------------------------------------------------------------------------------------------------
Total property, plant and equipment, net 907,829 861,107
----------------------------------------------------------------------------------------------------------
OTHER ASSETS
Deferred income taxes 22,782 21,055
Deferred charges and other 16,994 6,986
----------------------------------------------------------------------------------------------------------
Total other assets 39,776 28,041
----------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 1,203,041 $ 1,184,895
----------------------------------------------------------------------------------------------------------
</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, except share data) 2000 1999
-----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITAL AND LIABILITIES
CURRENT LIABILITIES
Long-term debt due within one year $ 18,648 $ 1,955
Notes payable to banks 168,000 268,000
Accounts payable 133,005 61,418
Accrued taxes 25,312 22,247
Customers' deposits 15,512 16,301
Amounts due customers 14,914 18,576
Accrued wages and benefits 24,256 19,404
Other 37,702 37,381
-----------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 437,349 445,282
-----------------------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Other 10,900 6,285
-----------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 10,900 6,285
-----------------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES -- --
-----------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION
Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized -- --
Common shareholders' equity
Common stock, $0.01 par value; 75,000,000 shares authorized, 30,350,802
shares outstanding at September 30, 2000, and
29,903,964 shares outstanding at September 30, 1999 304 299
Premium on capital stock 213,582 205,831
Capital surplus 2,802 2,802
Retained earnings 185,561 152,572
Deferred compensation plan 4,965 2,054
Treasury stock, at cost; 239,306 shares and 101,431 shares at September 30, 2000
and 1999, respectively (6,354) (2,054)
-----------------------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 400,860 361,504
Long-term debt 353,932 371,824
-----------------------------------------------------------------------------------------------------------------------------------
Total capitalization 754,792 733,328
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL AND LIABILITIES $ 1,203,041 $ 1,184,895
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
33
<PAGE> 12
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
Energen Corporation
---------------------------------------------------------------------------------------------------------------------------------
(in thousands, except share amounts)
---------------------------------------------------------------------------------------------------------------------------------
Common Stock
------------ Deferred
Number of Par Premium on Capital Retained Compensation Treasury
Shares Value Capital Stock Surplus Earnings Plan Stock
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE AT SEPTEMBER 30, 1997 28,796,218 $ 288 $ 185,841 $ 2,802 $ 112,212 $ -- $ --
Net income 36,249
Purchase of treasury shares (406)
Shares issued for:
Dividend reinvestment plan 172,612 2 3,369
Employe benefit plans 357,767 3 6,664 406
Deferred compensation obligation 873 (873)
Cash dividends - $0.625 per share (18,181)
---------------------------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1998 29,326,597 293 195,874 2,802 130,280 873 (873)
Net income 41,410
Purchase of treasury shares (442)
Shares issued for:
Dividend reinvestment plan 187,738 2 3,319
Employee benefit plans 389,629 4 6,638 442
Deferred compensation obligation 1,181 (1,181)
Cash dividends - $0.645 per share (19,118)
---------------------------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1999 29,903,964 299 205,831 2,802 152,572 2,054 (2,054)
Net income 53,018
Purchase of treasury shares (4,934)
Shares issued for:
Dividend reinvestment plan 57,920 1 1,438
Employee benefit plans 388,918 4 6,313 3,545
Deferred compensation obligation 2,911 (2,911)
Cash dividends - $0.665 per share (20,029)
---------------------------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 2000 30,350,802 $ 304 $ 213,582 $ 2,802 $ 185,561 $ 4,965 $ (6,354)
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
34
<PAGE> 13
CONSOLIDATED STATEMENTS OF CASH FLOW
<TABLE>
<CAPTION>
Energen Corporation
---------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, (in thousands) 2000 1999 1998
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income $ 53,018 $ 41,410 $ 36,249
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization 87,073 88,615 80,999
Deferred income taxes, net (5,400) (12,774) (15,407)
Deferred investment tax credits, net (448) (448) (469)
Gain on sale of assets (1,107) (4,180) (2,789)
Net change in:
Accounts receivable (18,857) (10,960) 7,131
Inventories (11,912) (3,039) 2,990
Accounts payable-gas purchases 2,559 14,115 (7,466)
Accounts payable-trade 2,010 (2,747) 4,719
Amounts due customers (3,662) 6,506 4,723
Other current assets and liabilities 7,119 14,938 11,711
Other, net (5,350) (816) 1,232
---------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 105,043 130,620 123,623
---------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property, plant and equipment (133,061) (120,204) (174,578)
Acquisition, net of cash acquired -- (123,816) --
Proceeds from sale of assets 2,647 56,884 7,636
Other, net (1,329) (951) 634
---------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (131,743) (188,087) (166,308)
---------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Payment of dividends on common stock (20,029) (19,118) (18,181)
Issuance of common stock 11,301 10,405 10,444
Purchase of treasury stock (4,934) (442) (406)
Reduction of long-term debt (1,205) (6,219) (885)
Proceeds from issuance of long-term debt -- -- 98,541
Net change in short-term debt issued to purchase
U.S. Treasury securities (140,917) 40,346 1,935
Net change in short-term debt 40,917 74,654 (50,934)
---------------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (114,867) 99,626 40,514
---------------------------------------------------------------------------------------------------------------------------------
Net change in cash and cash equivalents (141,567) 42,159 (2,171)
Cash and cash equivalents at beginning of period 145,390 103,231 105,402
---------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 3,823 $ 145,390 $ 103,231
---------------------------------------------------------------------------------------------------------------------------------
</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
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 (natural gas distribution), and in the
acquisition, development, exploration and production of oil and gas in the
continental United States (oil and gas operations). 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 Energen
Resources Corporation, 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 4.5 percent in 2000 and 1999 and 4.4 percent in 1998.
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 approvals received
from regulatory authorities, to be recovered from or refunded to customers in
future periods.
C. OIL AND GAS OPERATIONS
PROPERTY AND RELATED DEPLETION: Energen Resources follows the successful
efforts method of accounting for costs incurred in the exploration and
development of oil and gas reserves. Lease acquisition costs are capitalized
initially, and unproved properties are reviewed periodically to determine if
there has been impairment of the carrying value, with any such impairment
charged to exploration expense currently. Exploratory drilling costs are
capitalized pending determination of proved reserves. If proved reserves are
not discovered, the exploratory drilling costs are expensed. Other exploration
costs, including geological and geophysical costs, are expensed as incurred.
All development costs are capitalized. Depreciation, depletion and amortization
is determined on a 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.
OPERATING REVENUE: Energen Resources utilizes the sales method of accounting to
recognize oil and gas production revenue. Under the sales method, revenue is
recognized for the Company's total takes of oil and gas production, and
over-production liabilities are established only when it is estimated that a
property's over-produced volumes exceed the net share of remaining reserves for
such property. Energen Resources had no material production imbalances at
September 30, 2000. Gains and losses on the sale of property in the ordinary
course of business are classified as operating revenue.
DERIVATIVE COMMODITY INSTRUMENTS: Energen Resources periodically enters into
derivative commodity instruments to hedge its exposure to oil and gas price
fluctuations. Such instruments include regulated natural gas and crude oil
futures contracts traded on
36
<PAGE> 15
the New York Mercantile Exchange and over-the-counter swaps and basis hedges
with major energy derivative product specialists. These transactions have been
accounted for under the hedge method of accounting. Under this method, any
unrealized gains and losses are recorded as a receivable/payable with a
corresponding deferred gain/loss. Realized gains and losses are deferred as
liabilities or assets until the revenues from the related hedged volumes are
recognized in the income statement. Cash flows from derivative instruments are
recognized as incurred through changes in working capital. All hedge
transactions were subject to the Company's risk management policy, approved by
the Board of Directors, which does not permit speculative positions. To apply
the hedge method of accounting, management must demonstrate that a high
correlation existed between the value of the derivative commodity instrument
and the value of the item hedged. In doing so, management used the historic and
current relationships between the derivative instruments and the sales prices
of the hedged volumes. In fiscal year 2001, the Company is required to adopt
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as
amended, which establishes new accounting and reporting standards for
derivatives (see Note 12).
D. INCOME TAXES
The Company uses the liability method of accounting for income taxes in
accordance with SFAS No. 109, Accounting for Income Taxes. Under this method, a
deferred tax asset or liability is recognized for the estimated future tax
effects attributable to temporary differences as well as tax credit
carryforwards. Deferred tax assets and liabilities are measured using enacted
tax rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. The effect on
deferred tax assets and liabilities of a change in tax rates is recognized in
the period of the change.
E. CASH EQUIVALENTS
The Company includes highly liquid marketable securities and debt instruments
purchased with a maturity of three months or less in cash equivalents.
F. EARNINGS PER SHARE
The Company's basic earnings per share amounts have been computed based on the
weighted-average number of common shares outstanding. Diluted earnings per
share amounts reflect the assumed issuance of common shares for all potentially
dilutive securities (see Note 14).
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.
Significant estimates with regard to these financial statements include the
estimate of proved oil and gas reserves and the related present value of
estimated future net revenues therefrom (see Note 16).
37
<PAGE> 16
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 with modifications in 1985, 1987 and 1990. On October
7, 1996, RSE was extended, without change, 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. Under the inflation-based cost control measurement established by the
APSC, if a 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 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. In
fiscal 1999, the increase in O&M expense per customer was below the index
range; as a result the utility benefited by $0.7 million. Under RSE as
extended, a $4.5 million and a $6.6 million annual increase in revenue became
effective December 1, 1999 and 1998, respectively, and a $2.5 million annual
decrease in revenue became effective July 1, 1998.
Alagasco calculates a temperature adjustment to customers' monthly bills to
remove the effect of departures from normal temperatures on Alagasco's
earnings. The calculation is performed monthly, and the adjustments to
customers' bills are made in the same billing cycle in which the weather
variation occurs. Substantially all the customers to whom the temperature
adjustment applies are residential, small commercial and small industrial.
Alagasco's rate schedules for natural gas distribution charges contain a Gas
Supply Adjustment (GSA) rider, established in 1993, which permits the
pass-through to customers of changes in the cost of gas supply.
The APSC approved an Enhanced Stability Reserve (ESR), beginning fiscal year
1998, to which Alagasco may charge the full amount of: (1) extraordinary O&M
expenses resulting from force majeure events such as storms, severe weather,
and outages, when one or a combination of two such events results in more than
$200,000 of additional O&M expense during a fiscal year; or (2) individual
industrial and commercial customer revenue losses that exceed $250,000 during
the fiscal year, if such losses cause Alagasco's return on equity to fall below
13.15 percent. The APSC approved the reserve on October 6, 1998, in the amount
of $3.9 million; the maximum approved funding level of the ESR is $4 million.
Following a year in which a charge against the ESR is made, the APSC provides
for accretions to the ESR of no more than $40,000 monthly until the maximum
funding level is achieved.
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 are being returned to ratepayers over approximately 10 years. At
September 30, 2000 and 1999, a regulatory liability related to income taxes of
$1.4 million and $2.1 million, respectively, was included in the consolidated
financial statements.
As of November 1, 1998, the Company offered a Voluntary Early Retirement
Program to certain eligible employees. The APSC has allowed these costs to be
amortized over a three-year period. At September 30, 2000 and 1999, a
regulatory asset of $1.2 million and $2.4 million, respectively, for costs
associated with this early retirement program was included in the consolidated
financial statements.
The excess of total acquisition costs over book value of net assets of acquired
municipal gas distribution systems is included in utility plant and is being
amortized through Alagasco's rate-setting mechanism on a straight-line basis
over approximately 23 years. At September 30, 2000 and 1999, the net
acquisition adjustment was $13.4 million and $14.4 million, 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) 2000 1999
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Energen Corporation:
Medium-term Notes, interest ranging from 6.6% to 8.09%, for notes
redeemable September 20, 2001, to February 15, 2028 $ 225,000 $ 225,000
8% Debentures, due up to $1,000,000 annually to February 1, 2007 18,588 18,679
Series 1993 Notes, interest ranging from 6.25% to 7.25%, due annually
in payments ranging from $998,000 to $1,550,000 from March 1, 2001,
to March 1, 2008 9,910 11,024
Alabama Gas Corporation:
Medium-term Notes, interest ranging from 5.80% to 7.97%, for notes
redeemable December 15, 2000, to September 23, 2026 119,650 119,650
---------------------------------------------------------------------------------------------------------------------------------
Total 373,148 374,353
Less amounts due within one year 18,648 1,955
Less unamortized debt discount 568 574
---------------------------------------------------------------------------------------------------------------------------------
Total $ 353,932 $ 371,824
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The aggregate maturities of long-term debt for the next five years are as
follows:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
Years ending September 30, (in thousands)
---------------------------------------------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
$ 18,648 $ 17,072 $ 15,119 $ 22,145 $ 12,250
---------------------------------------------------------------------------------------------------------------------------------
</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, 2000, Energen had a tangible net worth of $401
million.
Energen and Alagasco had short-term credit lines and other credit facilities of
$249 million available as of September 30, 2000, for working capital needs;
Alagasco has been authorized to borrow up to $70 million of the available
credit lines by the APSC. At September 30, 1999, Energen borrowed $30 million
under a separate agreement to purchase U.S. Treasury securities for tax
planning purposes, and the securities were pledged as collateral on the debt.
While at September 30, 2000, the Company had no borrowings to purchase U.S.
Treasury securities, at September 30, 1999 and 1998, the Company had $140.9
million and $100.6 million, respectively, of borrowings to purchase securities
for tax planning. These securities matured in early October each year, and the
proceeds were used to repay such borrowings. The following is a summary of
information relating to notes payable to banks:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
As of September 30, (in thousands) 2000 1999 1998
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Amount outstanding $ 168,000 $ 238,000 $ 153,000
Amount outstanding under separate agreement -- 30,000 --
---------------------------------------------------------------------------------------------------------------------------------
Notes payable to banks $ 168,000 $ 268,000 $ 153,000
Available for borrowings 81,000 11,000 75,000
---------------------------------------------------------------------------------------------------------------------------------
Total $ 249,000 $ 279,000 $ 228,000
---------------------------------------------------------------------------------------------------------------------------------
Maximum amount outstanding at any month-end $ 168,000 $ 268,000 $ 180,000
Average daily amount outstanding $ 146,761 $ 154,427 $ 81,008
Weighted average interest rates based on:
Average daily amount outstanding 6.45% 5.40% 5.92%
Amount outstanding at year-end 6.95% 5.70% 5.77%
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Total interest expense for Energen in 2000, 1999 and 1998 was $37,769,000,
$37,173,000, and $30,001,000, respectively.
39
<PAGE> 18
4. SHAREHOLDERS' EQUITY
On January 28, 1998, Energen announced a 2-for-1 split of the Company's common
stock. The split was in the form of a 100 percent stock dividend and was
payable on March 2, 1998, to shareholders of record on February 13, 1998. All
per-share amounts and the number of shares of capital stock outstanding have
been retroactively adjusted to reflect the stock split. Effective January 30,
1998, the Restated Certificate of Incorporation of Energen Corporation was
amended to increase Energen's authorized common stock, par value $0.01 per
share, from 30,000,000 shares to 75,000,000 shares.
Amounts earned under the Deferred Compensation Plan and invested in common
stock of the Company have been recorded as treasury stock, along with the
related deferred compensation obligation in the Consolidated Statements of
Shareholders' Equity.
5. INCOME TAXES
The components of income taxes consist of the following:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, (in thousands) 2000 1999 1998
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Taxes estimated to be payable currently:
Federal $ 10,689 $ 11,639 $ 11,828
State 1,948 1,718 1,827
---------------------------------------------------------------------------------------------------------------------------------
Total current 12,637 13,357 13,655
---------------------------------------------------------------------------------------------------------------------------------
Taxes deferred:
Federal (6,027) (13,062) (15,342)
State 179 (160) (534)
---------------------------------------------------------------------------------------------------------------------------------
Total deferred (5,848) (13,222) (15,876)
---------------------------------------------------------------------------------------------------------------------------------
Total income tax expense (benefit) $ 6,789 $ 135 $ (2,221)
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Temporary differences and carryforwards which give rise to a significant
portion of deferred tax assets and liabilities for 2000 and 1999 are as
follows:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
As of September 30, (in thousands) 2000 1999
---------------------------------------------------------------------------------------------------------------------------------
Current Noncurrent Current Noncurrent
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Deferred tax assets:
Minimum tax credit $ -- $ 48,298 $ -- $ 39,068
Pension and other costs 3,980 -- 3,137 --
Other, net 14,229 1,507 12,263 1,881
---------------------------------------------------------------------------------------------------------------------------------
Subtotal 18,209 49,805 15,400 40,949
Valuation allowance -- -- -- --
---------------------------------------------------------------------------------------------------------------------------------
Total deferred tax assets 18,209 49,805 15,400 40,949
---------------------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Depreciation and basis differences -- 27,023 -- 19,891
Other, net 379 -- 709 3
---------------------------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities 379 27,023 709 19,894
---------------------------------------------------------------------------------------------------------------------------------
Net deferred tax assets $ 17,830 $ 22,782 $ 14,691 $ 21,055
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
40
<PAGE> 19
Total income tax expense (benefit) differs from the amount which would be
provided by applying the statutory federal income tax rate of 35 percent to
earnings before taxes as illustrated below:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, (in thousands) 2000 1999 1998
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Income tax expense at statutory federal income tax rate $ 20,932 $ 14,541 $ 11,910
Increase (decrease) resulting from:
Nonconventional fuels tax credits (14,405) (14,839) (14,453)
Enhanced oil recovery tax credits (457) (185) --
Deferred investment tax credits (448) (448) (469)
State income taxes, net of federal income tax benefit 1,452 1,087 894
Other, net (285) (21) (103)
---------------------------------------------------------------------------------------------------------------------------------
Total income tax expense (benefit) $ 6,789 $ 135 $ (2,221)
---------------------------------------------------------------------------------------------------------------------------------
Effective income tax rate (%) 11.35 0.32 (6.53)
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The Company files a consolidated federal income tax return with all of its
subsidiaries. As of September 30, 2000, the amount of minimum tax credit which
can be carried forward indefinitely to reduce future regular tax liability is
$48.3 million. No valuation allowance with respect to deferred taxes is deemed
necessary, as the Company anticipates generating adequate future taxable income
to realize the benefits of all deferred tax assets on the consolidated balance
sheets. The Company has evaluated its tax position and believes the financial
statements properly reflect the income tax matters of the Company.
6. EMPLOYEE BENEFIT PLANS
The Company has two defined benefit non-contributory pension plans: Plan A
which covers a majority of the employees and Plan B which covers employees
under certain labor union agreements. Benefits are based on years of service
and final earnings. The Company's policy is to use the projected unit credit
actuarial method for funding and financial reporting purposes.
The status of the plans was as follows:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
As of June 30, (in thousands) 2000 1999 2000 1999
---------------------------------------------------------------------------------------------------------------------------------
Plan A Plan B
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Projected benefit obligation:
Balance at beginning of year $ 73,841 $ 88,281 $ 18,227 $ 18,898
Service cost 1,988 2,653 265 299
Interest cost 5,573 6,193 1,361 1,338
Plan amendments -- -- -- 843
Actuarial loss (gain) (2,642) (8,205) (487) (1,803)
Special termination benefits -- 1,487 -- --
Benefits paid (7,066) (16,568) (2,364) (1,348)
---------------------------------------------------------------------------------------------------------------------------------
Balance at end of year 71,694 73,841 17,002 18,227
---------------------------------------------------------------------------------------------------------------------------------
Plan assets:
Fair value of plan assets at beginning of year 92,575 90,661 24,043 23,081
Actual return on plan assets 10,972 18,482 1,882 2,310
Benefits paid (7,066) (16,568) (2,364) (1,348)
---------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year 96,481 92,575 23,561 24,043
---------------------------------------------------------------------------------------------------------------------------------
Amounts recognized in the
Consolidated Balance Sheets:
Funded status of plan 24,787 18,734 6,559 5,816
Unrecognized actuarial loss (gain) (32,238) (23,897) (6,458) (5,621)
Unrecognized prior service cost 2,555 2,790 1,163 1,398
Unrecognized net transition obligation (asset) (1,069) (1,877) 114 170
---------------------------------------------------------------------------------------------------------------------------------
Accrued pension asset (liability) $ (5,965) $ (4,250) $ 1,378 $ 1,763
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
41
<PAGE> 20
The components of net pension expense were:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, (in thousands) 2000 1999 1998 2000 1999 1998
---------------------------------------------------------------------------------------------------------------------------------
Plan A Plan B
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Components of net periodic benefit cost:
Service cost $ 1,988 $ 2,653 $ 2,386 $ 265 $ 299 $ 224
Interest cost 5,573 6,193 5,842 1,361 1,338 1,261
Expected return on assets (5,566) (5,938) (5,709) (1,577) (1,510) (1,346)
Prior service cost amortization 235 235 5 235 235 207
Transition amortization (808) (808) (808) 57 57 57
---------------------------------------------------------------------------------------------------------------------------------
Net periodic expense $ 1,422 $ 2,335 $ 1,716 $ 341 $ 419 $ 403
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
As of September 30, 2000 1999 2000 1999
---------------------------------------------------------------------------------------------------------------------------------
Plan A Plan B
<S> <C> <C> <C> <C>
Weighted average rate assumptions in pension actuarial calculations:
Discount rate 8.00% 7.75% 8.00% 7.75%
Expected return on plan assets 8.25% 8.25% 8.25% 8.25%
Rate of compensation increase 5.50% 5.25% -- --
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The Company has supplemental retirement plans with certain key executives
providing payments on retirement, termination, death or disability. Expense
under these agreements for 2000, 1999 and 1998 was $372,000, $(75,000) and
$(54,000), respectively. At June 30, 2000 and 1999, the accumulated
post-retirement benefit obligation related to these agreements was $3,204,000
and $2,620,000, respectively, and the projected benefit obligation was
$10,356,000 and $7,189,000, respectively. A prepaid post-retirement benefit
asset of $566,000 and $844,000 was recorded at June 30, 2000 and 1999,
respectively.
In addition to providing pension benefits, the Company provides certain
post-retirement health care and life insurance benefits. Substantially all of
the Company's employees may become eligible for certain benefits if they reach
normal retirement age while working for the Company. The projected unit credit
actuarial method was used to determine the normal cost and actuarial liability.
The status of the post-retirement benefit programs was as follows:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
As of June 30, (in thousands) 2000 1999 2000 1999
---------------------------------------------------------------------------------------------------------------------------------
Salaried Employees Union Employees
---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Projected post-retirement benefit obligation:
Balance at beginning of year $ 29,144 $ 29,312 $ 37,423 $ 37,751
Service cost 1,092 1,464 1,876 2,039
Interest cost 2,203 2,013 2,852 2,599
Actuarial loss (gain) (1,146) (2,530) (1,635) (3,709)
Special termination benefits -- 338 -- --
Benefits paid (1,482) (1,453) (1,225) (1,257)
---------------------------------------------------------------------------------------------------------------------------------
Balance at end of year 29,811 29,144 39,291 37,423
---------------------------------------------------------------------------------------------------------------------------------
Plan assets:
Fair value of plan assets at beginning of year 35,494 30,476 26,702 23,081
Actual return on plan assets 4,186 4,896 3,928 2,468
Company contribution 2,806 1,575 6,005 2,410
Benefits paid (1,482) (1,453) (1,225) (1,257)
---------------------------------------------------------------------------------------------------------------------------------
Balance at end of year 41,004 35,494 35,410 26,702
---------------------------------------------------------------------------------------------------------------------------------
Amounts recognized in the
Consolidated Balance Sheets:
Funded status of plan 11,193 6,350 (3,881) (10,721)
Unrecognized actuarial loss (gain) (19,435) (16,468) (11,274) (7,266)
Unrecognized net transition obligation 9,395 10,118 16,702 17,987
---------------------------------------------------------------------------------------------------------------------------------
Accrued post-retirement asset $ 1,153 $ -- $ 1,547 $ --
---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
42
<PAGE> 21
Net periodic post-retirement benefit expense included the following:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, (in thousands) 2000 1999 1998 2000 1999 1998
-----------------------------------------------------------------------------------------------------------------------------------
Salaried Employees Union Employees
-----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Components of net periodic benefit cost:
Service cost $ 1,092 $ 1,464 $ 967 $ 1,876 $ 2,039 $ 1,314
Interest cost 2,203 2,013 2,049 2,852 2,599 2,612
Expected return on assets (1,721) (1,448) (1,189) (1,292) (1,156) (737)
Actuarial loss (gain) (1,029) (590) (510) (271) (129) (107)
Transition amortization 723 723 723 1,285 1,285 1,285
-----------------------------------------------------------------------------------------------------------------------------------
Net periodic expense $ 1,268 $ 2,162 $ 2,040 $ 4,450 $ 4,638 $ 4,367
-----------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------------
As of September 30, 2000 1999 2000 1999
-----------------------------------------------------------------------------------------------------------------------------------
Salaried Employees Union Employees
-----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Weighted average rate assumptions
in post-retirement actuarial calculations:
Discount rate 8.00% 7.75% 8.00% 7.75%
Expected return on plan assets 8.25% 8.25% 8.25% 8.25%
Rate of compensation increase 5.50% 5.25% -- --
Health care cost trend rate 7.50% 7.50% 7.50% 7.50%
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The weighted average health care cost trend rate used in determining the
accumulated post-retirement benefit obligation 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 percentage point would
increase the accumulated post-retirement benefit obligation by $811,000 and the
net periodic post-retirement benefit cost by $31,000. For union employees,
increasing the weighted average health care cost trend rate by 1 percentage
point would increase the accumulated post-retirement benefit obligation by
$2,880,000 and the net periodic post-retirement benefit cost by $318,000.
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.
The Company had no expense for the year ended September 30, 2000. Expense for
the years ended September 30, 1999 and 1998, was $177,000 and $173,000,
respectively.
7. COMMON STOCK PLANS
A majority of Company employees are eligible to participate in the Energen
Employee Savings Plan (ESP) by investing a portion of their compensation in the
ESP, with the Company matching a part of the employee investment by contributing
Company common stock (new issue or treasury shares) or funds for the purchase of
Company common stock. The ESP also contains employee stock ownership plan
provisions. At September 30, 2000, 714,141 common shares were reserved for
issuance under the ESP. Expense associated with Company contributions to the ESP
was $3,381,000, $3,421,000 and $3,168,000 for 2000, 1999 and 1998, respectively.
In 1992 the Company adopted the Energen Corporation 1992 Long-Range Performance
Plan which provides for the award of up to 1,000,000 performance units, with
each unit equal to the market value of one share of common stock, to eligible
employees based on predetermined performance criteria at the end of a four-year
award period. Under the Plan, a portion of the performance units is payable with
Company common stock; accordingly, 700,000 shares have been reserved for
issuance. Under the Plan, 102,860, 100,100, and 97,545 performance units were
awarded in 2000, 1999 and 1998, respectively, leaving 78,673 performance units
available for award as of September 30, 2000. The Company recorded expense of
$4,448,000, $1,530,000 and $2,815,000 for 2000, 1999 and 1998, respectively,
under the Plan.
43
<PAGE> 22
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, 1,500,000 shares were added to the Plan. As of
September 30, 2000, 1,001,942 common shares were reserved under this Plan.
On November 27, 1997, the Company adopted the Energen Corporation 1997 Stock
Incentive Plan. The 1997 Stock Incentive Plan, along with the Energen
Corporation 1988 Stock Option Plan, provides for the grant of incentive stock
options, non-qualified stock options, or a combination thereof to officers and
key employees. Options granted under the Plans provide for purchase of the
Company's common stock at not less than the fair market value on the date the
option is granted. In addition, the 1997 Stock Incentive Plan provides for the
grant of restricted stock with 12,500 and 5,500 shares being awarded in 2000 and
1999, respectively. The sale or transfer of the shares is limited during the
restricted period. The Company recorded expense of $97,264 and $30,670 in 2000
and 1999, respectively, related to the restricted stock. Under the 1988 Stock
Option Plan, 540,000 shares of the Company's common stock which were reserved
for issuance have been granted. Under the 1997 Stock Incentive Plan, 1,300,000
shares of the Company's common stock have been reserved for issuance. All
outstanding options are incentive or non-qualified, vest over three years from
date of grant, and expire 10 years from the date of grant. Transactions under
the Plans are summarized as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
1997 Stock Incentive Plan 1988 Stock Option Plan
------------------------------------------------------------------------------------------------------------------------------------
Weighted Average Weighted Average
Shares Exercise Price Shares Exercise Price
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Outstanding at September 30, 1997 -- $ -- 423,112 $10.56
Granted 256,320 18.25 80,680 18.25
Exercised -- -- (6,000) 8.38
------------------------------------------------------------------------------------------------------------------------------------
Outstanding at September 30, 1998 256,320 18.25 497,792 11.83
Granted 78,950 18.25 -- --
Exercised -- -- (73,716) 9.05
Forfeited -- -- (2,000) 18.25
------------------------------------------------------------------------------------------------------------------------------------
Outstanding at September 30, 1999 335,270 18.25 422,076 12.29
Granted 108,500 18.8125 -- --
Exercised (40,262) 18.25 (157,660) 9.65
------------------------------------------------------------------------------------------------------------------------------------
Outstanding at September 30, 2000 403,508 $ 18.40 264,416 $13.86
------------------------------------------------------------------------------------------------------------------------------------
Exercisable at September 30, 1998 -- $ -- 333,112 $ 9.48
Exercisable at September 30, 1999 85,430 $ 18.25 320,280 $10.90
Exercisable at September 30, 2000 158,488 $ 18.25 237,836 $13.37
------------------------------------------------------------------------------------------------------------------------------------
Remaining reserved for issuance
at September 30, 2000 838,230 -- -- --
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The following table summarizes information about options outstanding as of
September 30, 2000:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
1997 Stock Incentive Plan 1988 Stock Option Plan
------------------------------------------------------------------------------------------------------------------------------------
Weighted Average Weighted Average
Range of Remaining Range of Remaining
Exercise Prices Shares Contractual Life Exercise Prices Shares Contractual Life
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$18.25-$18.81 403,508 7.85 years $8.38-$11.06 101,400 3.14 years
$15.00-$18.25 163,016 6.84 years
------------------------------------------------------------------------------------------------------------------------------------
$18.25-$18.81 403,508 7.85 years $8.38-$18.25 264,416 5.42 years
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The weighted-average grant-date fair value of options granted in 2000, 1999 and
1998 were $5.91, $5.42, and $4.94. The fair value of each option grant was
estimated using the Black-Scholes option-pricing model. The Company has adopted
the disclosure-only provisions of SFAS No. 123, Accounting for Stock-Based
Compensation. Accordingly, no compensation expense has been recognized for its
stock options. Had compensation cost for these options been determined in
accordance with SFAS No. 123, the Company's net income and diluted earnings per
share would have been $52.5 million, or $1.73 per share, in 2000, $40.9 million,
or $1.37 per share, in 1999, and $35.8 million, or $1.22 per share, in 1998.
44
<PAGE> 23
In 1992 the Company adopted the Energen Corporation 1992 Directors Stock Plan to
pay part of the compensation of its non-employee directors in shares of the
Company's common stock. Under the Plan, 3,254, 4,914 and 6,813 shares were
issued in 2000, 1999 and 1998, respectively, leaving 149,439 shares reserved for
issuance as of September 30, 2000.
On April 26, 2000, the Company authorized the repurchase of up to 1,000,000
shares of the Company's common stock, in addition to the 500,000 shares
authorized on May 25, 1994. In 2000 and 1999 the Company repurchased 290,000 and
30,189 shares, respectively. As of September 30, 2000, a total of 939,711 shares
remain authorized for future repurchase.
On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan)
designed to protect shareholders from coercive or unfair takeover tactics. Under
certain circumstances, the 1998 Plan provides shareholders with the right to
acquire the Company's Series 1998 Junior Participating Preferred Stock (or, in
certain cases, securities of an acquiring person) at a significant discount.
Terms and conditions are set forth in a Rights Agreement between the Company and
its Rights Agent. Under the 1998 Plan, one right is associated with each
outstanding share of common stock. Rights outstanding under the 1998 Plan at
September 30, 2000, were convertible into 303,508 shares of Series 1998 Junior
Participating Preferred Stock (1/100 share of preferred stock for each full
right) subject to adjustment upon occurrence of certain take-over related
events. No rights were exercised or exercisable during the period. The price at
which the rights would be exercised is $70 per right, subject to adjustment upon
occurrence of certain take-over related events. In general, absent certain
take-over related events as described in the Plan, the rights may be redeemed
prior to the July 27, 2008, expiration for $0.01 per right.
8. 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 year 2008.
These contracts typically contain minimum demand charge obligations on the part
of the Company.
The Company has three-way pricing, physical sales contracts in place for
approximately 23 percent of its estimated gas production in fiscal year 2002.
These contracts provide for Energen Resources to receive a basin-specific
weighted average price between $2.82 and $3.94 per Mcf. If the market price
falls between $2.40 and $2.82 per Mcf, Energen Resources will receive $2.82 per
Mcf. If the market price falls below $2.40 per Mcf, Energen Resources will
receive the market price plus a premium of $0.33-$0.45, depending on the
contracts. In fiscal year 2003, the Company has three-way pricing, physical
sales contracts in place for approximately 17 percent of its estimated gas
production. These contracts provide for Energen Resources to receive a
basin-specific weighted average price between $2.72 and $3.94 per Mcf. If the
market price falls between $2.40 and $2.72 per Mcf, Energen Resources will
receive $2.72 per Mcf. If the market price falls below $2.40 per Mcf, Energen
Resources will receive the market price plus a premium of $0.23-$0.35, depending
on the contracts.
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. An investigation of the
sites does not indicate the present need for remediation activities. Management
expects that, should remediation of any such sites be required in the future,
Alagasco's share, if any, of such costs will not materially affect the results
of operations or financial condition of Alagasco.
Energen Resources is subject to various environmental regulations. Management
believes that Energen Resources 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
Energen Resources has operating agreements with various joint venture partners,
environmental costs, if any, would be shared proportionately.
LEGAL MATTERS: Energen and its affiliates are, from time to time, parties to
various pending or threatened legal proceedings. Certain of these lawsuits
include claims for punitive damages in addition to other specified relief. Based
upon information presently available, and in light of available legal and other
defenses, contingent liabilities arising from threatened and pending litigation
are not considered material in relation to the respective financial positions of
Energen and its affiliates. It should be noted, however, that Energen and its
affiliates conduct business in Alabama and other jurisdictions in which the
magnitude and frequency of punitive damage awards may bear little or no relation
to culpability or actual damages, thus making it increasingly difficult to
predict litigation results. Various legal proceedings arising in the normal
course of business are in progress currently, and the Company has accrued a
provision for estimated costs.
45
<PAGE> 24
LEASE OBLIGATIONS: In January 1999 Alagasco closed on a sale-leaseback of the
Company's headquarters building. The proceeds from the sale approximated the
investment in the facility. The building is being leased back from the purchaser
over a 25-year lease term and the related lease is accounted for as an operating
lease. Total lease payments related to leases included as operating lease
expense, inclusive of the sale-leaseback, were $6,267,000, $5,665,000 and
$5,271,000 in 2000, 1999 and 1998, respectively. Minimum future rental payments
required after 2000 under leases with initial or remaining noncancelable lease
terms in excess of one year are as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Years ending September 30, (in thousands)
------------------------------------------------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 2006 and thereafter
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$ 3,848 $ 3,859 $ 3,595 $ 3,232 $ 2,818 $ 36,534
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
9. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental information concerning cash flow activities is as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, (in thousands) 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest paid $ 37,717 $ 36,646 $ 28,442
Income taxes paid $ 11,885 $ 12,925 $ 12,764
Noncash investing activities
Capitalized depreciation $ 217 $ 265 $ 187
Allowance for funds used during construction $ 1,172 $ 374 $ 400
Noncash financing activities (debt issuance costs) $ -- $ -- $ 875
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
10. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
FINANCIAL INSTRUMENTS: The fair value of cash and cash equivalents, trade
receivables (net of allowance), and short-term debt approximates fair value due
to the short maturity of the instruments. The fair value of fixed-rate long-term
debt, including the current portion, with a carrying value of $373,148,000,
would be $353,470,000 at September 30, 2000. The fair value was based on the
market value of debt with similar maturities and current interest rates.
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
2000, 1999 and 1998, the Company sold $6,879,000, $6,391,000 and $8,100,000,
respectively, of installment receivables. At September 30, 2000 and 1999, the
balance of these installment receivables was $15,280,000 and $15,690,000,
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.
PRICE RISK: Energen Resources periodically enters into derivative commodity
instruments to hedge its exposure to oil and gas price fluctuations. Such
instruments include regulated natural gas and crude oil futures contracts traded
on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps and basis
hedges with major energy derivative product specialists. These transactions have
been accounted for under the hedge method of accounting. Under this method, any
unrealized gains and losses are recorded as a receivable/payable with a
corresponding deferred gain/loss. Realized gains and losses are deferred as
liabilities or assets until the revenues from the related hedged volumes are
recognized in the income statement. Cash flows from derivative instruments are
recognized as incurred through changes in working capital. The Company had
current deferred hedging losses of $83.5 million and $16.5 million included in
prepayments and other on the consolidated balance sheet at September 30, 2000
and 1999, respectively. The Company had non-current deferred hedging losses of
$5.9 million included in deferred charges and other on the consolidated balance
sheet at September 30, 2000.
46
<PAGE> 25
At September 30, 2000, Energen Resources had entered into contracts and swaps
for 37 Bcf of its fiscal year 2001 gas production at an average NYMEX price of
$2.76 per Mcf, 950 MBbl of its oil production at an average NYMEX price of
$24.32 per barrel and 150 MBbl of oil production with a collar price of $20.00
to $25.24 per barrel. Energen also had basin-specific hedges in place for 150
MBbl of oil at an average realized price of $23.53 per barrel. Subsequent to
September 30, 2000, Energen Resources had entered into additional contracts and
swaps for fiscal year 2001, resulting in a total of 1,188 MBbl of oil production
hedged at an average NYMEX price of $25.30 per barrel for fiscal year 2001. The
oil collar and basin-specific hedges remain unchanged. Realized prices are
anticipated to be lower than hedged prices due to basis difference and other
factors. To help mitigate this variance, the Company had hedged the basis
difference on 17.8 Bcf of its fiscal year 2001 basin-specific production.
The program has been extended into fiscal year 2002, with contracts and swaps in
place for 6 Bcf of gas production at an average NYMEX price of $3.19 per Mcf.
The Company had hedged the basis difference on 6 Bcf of its fiscal year 2002,
basin-specific production.
All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors, which does not permit speculative positions.
To apply the hedge method of accounting, management must demonstrate that a high
correlation exists between the value of the derivative commodity instrument and
the value of the item hedged. In doing so, management uses the historic and
current relationships between the derivative instruments and the sales prices of
the hedged volumes.
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 approximately 473,000 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 primarily are generated from the sale of produced natural gas and
oil. This industry concentration has the potential to affect the Company's
overall exposure to credit risk, either positively or negatively, in that the
customers may be affected similarly 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.
11. ACCOUNTING FOR LONG-LIVED ASSETS
SFAS No.121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of, requires that an impairment loss be
recognized when the carrying amount of an asset exceeds the sum of the
undiscounted estimated future cash flow of the asset. The Statement also
provides that all long-lived assets to be disposed of be reported at the lower
of the carrying amount or fair value. Accordingly, during the third fiscal
quarter of 2000, Energen Resources recorded a pre-tax writedown of $3.5 million
as additional depreciation, depletion and amortization expense caused by a
downward reserve revision in a small oil and gas field, adjusting the carrying
amount of the properties to their fair value based upon expected future
discounted cash flows.
During the second fiscal quarter of 1998, Energen Resources recorded a pre-tax
writedown of $4.7 million as additional depreciation, depletion and amortization
on certain oil and gas properties, adjusting the carrying amount of the
properties to their fair value based upon expected future discounted cash flows.
This writedown primarily reflected the impact of a decline in crude oil prices.
47
<PAGE> 26
12. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD
In June 1998, the FASB issued SFAS No. 133 (subsequently amended by SFAS Nos.
137 and 138), which established new accounting and reporting standards for
derivative instruments. The Company is required to adopt this statement on
October 1, 2000. This statement requires the Company to recognize all
derivatives as either assets or liabilities on the balance sheet and measure the
effectiveness of the hedges, or the degree that the gain (loss) for the hedging
instrument offsets the loss (gain) on the hedged item, at fair value each
reporting period. The effective portion of the gain or loss on the derivative
instrument will be recognized in other comprehensive income as a component of
equity until the hedged item is recognized in earnings. The ineffective portion
of the derivative's change in fair value is required to be recognized in
earnings immediately. During the Company's implementation process, management
has identified oil and gas derivatives which qualify as cash flow hedges.
Unrealized gains and losses resulting from changes in the fair value of the
effective portion of the derivatives will be reported directly to shareholders'
equity. Effective October 1, 2000, the Company reclassified deferred hedging
losses included in the consolidated balance sheet at September 30, 2000, to
other comprehensive loss reflected as a reduction of equity in accordance with
SFAS No. 133 in the amount of $55.4 million, net of tax. While certain
derivatives not qualifying for hedge accounting will directly impact reported
net income and have potential earnings volatility to the Company, management
does not believe the adoption of SFAS No. 133 will have a material impact on the
results of operations of the Company.
13. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following data summarizes quarterly operating results. The Company's
business is seasonal in character and strongly influenced by weather conditions.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
2000 Fiscal Quarters
(in thousands, except per share amounts) First Second Third Fourth
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $ 129,009 $ 207,456 $ 116,567 $ 102,563
Operating income $ 19,394 $ 56,364 $ 13,158 $ 6,885
Net income (loss) $ 9,136 $ 41,166 $ 4,458 $ (1,742)
Diluted earnings (loss) per average common share $ 0.30 $ 1.36 $ 0.15 $ (0.06)
Basic earnings (loss) per average common share $ 0.30 $ 1.37 $ 0.15 $ (0.06)
------------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
1999 Fiscal Quarters
(in thousands, except per share amounts) First Second Third Fourth
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $ 113,968 $ 188,390 $ 108,520 $ 86,639
Operating income $ 12,961 $ 50,779 $ 13,402 $ 241
Net income (loss) $ 3,842 $ 42,369 $ 3,513 $ (8,314)
Diluted earnings (loss) per average common share $ 0.13 $ 1.42 $ 0.12 $ (0.28)
Basic earnings (loss) per average common share $ 0.13 $ 1.43 $ 0.12 $ (0.28)
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
14. RECONCILIATION OF EARNINGS PER SHARE
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Years ended September 30,
(in thousands, except per share amounts) 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
Per Share Per Share Per Share
Income Shares Amount Income Shares Amount Income Shares Amount
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Basic EPS $ 53,018 30,108 $ 1.76 $ 41,410 29,644 $ 1.40 $ 36,249 29,084 $ 1.25
Effect of dilutive securities
Long-range performance
shares 126 160 167
Stock options 125 117 187
------------------------------------------------------------------------------------------------------------------------------------
Diluted EPS $ 53,018 30,359 $ 1.75 $ 41,410 29,921 $ 1.38 $ 36,249 29,438 $ 1.23
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
48
<PAGE> 27
15. ACQUISITION
On October 15, 1998, Energen Resources purchased the stock of the TOTAL Minatome
Corporation (TOTAL), a Houston-based unit of TOTAL American Holding Inc.
Immediately upon closing the transaction, Energen Resources sold a 31 percent
undivided interest in TOTAL's net assets to Westport Oil and Gas Company Inc.
Energen Resources' net adjusted price totaled approximately $137.5 million,
including the assumption of certain legal and financial obligations. Energen
Resources gained an estimated 200 Bcfe of proved domestic oil and natural gas
reserves. The acquisition was accounted for as a purchase, and the results of
operations since the acquisition date are included in the consolidated financial
statements. A summary of net assets acquired follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
(in thousands)
------------------------------------------------------------------------------------------------------------------------------------
<S> <C>
Oil and gas properties $ 137,533
Less liabilities assumed (13,288)
Less cash acquired (429)
------------------------------------------------------------------------------------------------------------------------------------
Acquisition cost, net of cash acquired $ 123,816
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
16. OIL AND GAS OPERATIONS (UNAUDITED)
The following schedules detail historical financial data of the Company's oil
and gas operations. Certain terms appearing in the schedules are prescribed by
the Securities and Exchange Commission (SEC) and are briefly described as
follows:
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 and expired leaseholds.
DEVELOPMENT COSTS include costs necessary to gain access to, prepare and equip
development wells in areas of proved reserves.
PRODUCTION (LIFTING) COSTS include costs incurred to operate and maintain wells.
GROSS REVENUES are reported after deduction of royalty interest payments.
GROSS WELL OR ACRE is a well or acre in which a working interest is owned.
NET WELL OR ACRE is deemed to exist when the sum of fractional ownership working
interests in gross wells or acres equals one.
DRY WELL is an exploratory or a development well found to be incapable of
producing either oil or gas in sufficient quantities to justify completion as an
oil or gas well.
PRODUCTIVE WELL is an exploratory or a development well that is not a dry well.
CAPITALIZED COSTS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
As of September 30, (in thousands) 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Proved $ 707,236 $ 659,522 $ 502,025
Unproved 6,530 10,463 14,015
------------------------------------------------------------------------------------------------------------------------------------
Total capitalized costs 713,766 669,985 516,040
Accumulated depreciation, depletion and amortization 165,447 129,839 88,306
------------------------------------------------------------------------------------------------------------------------------------
Capitalized costs, net $ 548,319 $ 540,146 $ 427,734
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
49
<PAGE> 28
COSTS INCURRED The following table sets forth costs incurred in property
acquisition, exploration and development activities and includes both
capitalized costs and costs charged to expense during the year:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, (in thousands) 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Property acquisition:
Proved $ 2,086 $ 143,693 $ 82,814
Unproved 350 266 1,933
Exploration 1,472 1,919 5,593
Development 66,717 55,487 35,307
------------------------------------------------------------------------------------------------------------------------------------
Total costs incurred $ 70,625 $ 201,365 $ 125,647
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
RESULTS OF OPERATIONS The following table sets forth results of the Company's
oil and gas operations:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, (in thousands) 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Gross revenues $ 188,601 $ 167,476 $ 129,978
Production (lifting) costs 72,820 70,230 48,388
Exploration expense* 4,878 4,938 5,773
Depreciation, depletion and amortization** 57,253 60,891 54,411
Income tax expense (benefit) 5,121 (3,045) (5,870)
------------------------------------------------------------------------------------------------------------------------------------
Results of operations from producing activities $ 48,529 $ 34,462 $ 27,276
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
* Includes a $3.8 million, $3.3 million, and $2.5 million writedown of a portion
of an unproved leasehold in 2000, 1999, and 1998, respectively
** Includes a writedown of $3.5 million and $4.7 million in 2000 and 1998,
respectively, under SFAS 121 (see Note 11)
AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Average sales price:
Gas (per Mcf) $ 2.49 $ 2.21 $ 2.21
Oil (per barrel) $ 18.11 $ 11.92 $ 14.96
Natural gas liquids (per barrel) $ 16.04 $ 9.58 $ 8.65
Average production (lifting) cost (per Mcfe) $ 1.03 $ 0.91 $ 0.84
Average depreciation rate (per Mcfe) $ 0.76 $ 0.79 $ 0.87
------------------------------------------------------------------------------------------------------------------------------------
</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, 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Exploratory:
Productive 0.3 0.9 0.7
Dry -- 1.3 1.0
------------------------------------------------------------------------------------------------------------------------------------
Total 0.3 2.2 1.7
------------------------------------------------------------------------------------------------------------------------------------
Development:
Productive 70.6 62.4 19.5
Dry 1.5 2.3 2.9
------------------------------------------------------------------------------------------------------------------------------------
Total 72.1 64.7 22.4
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
As of September 30, 2000, the Company was participating in the drilling of 5
gross development wells, with the Company's interest equivalent to 1.4 wells.
50
<PAGE> 29
PRODUCTIVE WELLS AND ACREAGE The following table sets forth the total gross and
net productive gas and oil wells as of September 30, 2000, and developed and
undeveloped acreage as of the latest practicable date prior to year-end:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Gross Net
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Gas Wells 3,144 1,565
Oil Wells 2,239 514
------------------------------------------------------------------------------------------------------------------------------------
Developed Acreage 1,000,393 518,349
Undeveloped Acreage 269,425 48,346
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
There were 64 wells with multiple completions in 2000. All wells and acreage are
located onshore in the United States, with the majority of the net undeveloped
acreage located in the Permian Basin.
OIL AND GAS OPERATIONS The calculation of proved reserves is made pursuant to
rules prescribed by the SEC. Such rules, in part, require that only proved
categories of reserves be disclosed and that reserves and associated values be
calculated using current realizable prices and costs. Changes to 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 available. Accordingly, the amount of actual future production may vary
significantly from the amount of reserves disclosed. See Note 10 for pricing
information regarding the hedging activities of the Company. The proved reserves
are located in the United States. Until the 1999 disposition of offshore
properties, reserves were located both onshore and offshore.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Year ended September 30, 2000 Gas MMcf Oil MBbl NGL MBbl
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Proved reserves at beginning of year 740,001 24,719 21,937
Revisions of previous estimates 37,028 (2,601) 3,250
Purchases 1,819 1,997 308
Discoveries and other additions 47,146 2,890 1,942
Production (48,084) (2,304) (1,429)
Sales (454) (183) (1)
------------------------------------------------------------------------------------------------------------------------------------
Proved reserves at end of year 777,456 24,518 26,007
------------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves at end of year 691,287 18,714 22,906
------------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Year ended September 30, 1999 Gas MMcf Oil MBb l NGL MBbl
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Proved reserves at beginning of year 542,039 19,845 17,292
Revisions of previous estimates 66,522 2,575 2,546
Purchases 149,158 8,870 --
Discoveries and other additions 57,452 1,851 2,869
Production (53,855) (3,122) (762)
Sales (21,315) (5,300) (8)
------------------------------------------------------------------------------------------------------------------------------------
Proved reserves at end of year 740,001 24,719 21,937
------------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves at end of year 644,702 20,332 18,696
------------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Year ended September 30, 1998 Gas MMcf Oil MBbl NGL MBbl
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Proved reserves at beginning of year 544,283 9,128 12,378
Revisions of previous estimates (13,006) (1,402) 2,211
Purchases 21,590 13,284 441
Discoveries and other additions 44,347 278 3,079
Production (43,853) (1,433) (817)
Sales (11,322) (10) --
------------------------------------------------------------------------------------------------------------------------------------
Proved reserves at end of year 542,039 19,845 17,292
------------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves at end of year 493,770 14,053 14,214
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
During fiscal 2000, Energen Resources invested approximately $2.1 million in
proved property acquisitions. Energen Resources also sold approximately 2 Bcfe
of proved reserves and recorded net pre-tax gains of $1.1 million.
51
<PAGE> 30
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES The standardized measure of discounted future net cash flows is
not intended, nor should it be interpreted, to present the fair market value of
the Company's crude oil and natural gas reserves. An estimate of fair market
value would take into consideration factors such as, but not limited to, the
recovery of reserves not presently classified as proved reserves, anticipated
future changes in prices and costs, and a discount factor more representative of
the time value of money and the risks inherent in reserve estimates. At
September 30, 2000, 1999 and 1998, the Company had deferred hedging losses of
$89.4 million and $16.5 million and deferred hedging gains of $0.6 million,
respectively, which are excluded from the calculation of standardized measure of
future net cash flows.
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, (in thousands) 2000 1999 1998
-------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Future gross revenues $4,824,681 $2,272,586 $1,109,829
Future production costs 1,379,913 801,640 476,589
Future development costs 110,660 102,651 67,459
-------------------------------------------------------------------------------------------------------------------------------
Future net cash flows before income taxes 3,334,108 1,368,295 565,781
Future income tax expense including tax credits 1,073,051 288,227 12,917
-------------------------------------------------------------------------------------------------------------------------------
Future net cash flows after income taxes 2,261,057 1,080,068 552,864
Discount at 10% per annum 1,155,792 466,214 195,606
-------------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $1,105,265 $ 613,854 $ 357,258
-------------------------------------------------------------------------------------------------------------------------------
</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) 2000 1999 1998
-------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at beginning of year $ 613,854 $ 357,258 $ 439,354
-------------------------------------------------------------------------------------------------------------------------------
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future
development costs 715,746 165,092 (175,156)
Net changes due to revisions in quantity estimates 37,049 55,993 (4,993)
Development costs incurred, previously estimated 39,589 24,529 13,722
Accretion of discount 61,385 35,725 43,935
Other 6,850 (12,976) (22,329)
-------------------------------------------------------------------------------------------------------------------------------
Total Revisions 860,619 268,363 (144,821)
New field discoveries and extensions, net of future
production and development costs 110,727 40,105 9,989
Sales of oil and gas produced, net of production costs (157,533) (93,314) (69,732)
Purchases 17,657 157,437 50,010
Sales (1,110) (18,843) (12,713)
Net change in income taxes (338,949) (97,152) 85,171
-------------------------------------------------------------------------------------------------------------------------------
Net change in standardized measure of discounted future
net cash flows 491,411 256,596 (82,096)
-------------------------------------------------------------------------------------------------------------------------------
Balance at end of year $1,105,265 $613,854 $ 357,258
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>
52
<PAGE> 31
COALBED METHANE ACTIVITIES Energen Resources is actively engaged in the
production of pipeline-quality natural gas from coal seams (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
Energen Resources, certain data are separately disclosed below.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
Years ended September 30, 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Proved reserves at beginning of year (MMcf) 262,840 222,481 230,323
Revisions of previous estimates 20,076 55,120 6,960
Purchases -- -- --
Production (14,481) (14,761) (14,802)
------------------------------------------------------------------------------------------------------------------------------------
Proved reserves at end of year (MMcf) 268,435 262,840 222,481
------------------------------------------------------------------------------------------------------------------------------------
Estimated proved reserves qualifying for tax credits (MMcf) 24,777 35,602 45,309
------------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs (in thousands) $128,809 $133,773 $139,001
------------------------------------------------------------------------------------------------------------------------------------
Gross wells in which the company has working and/or revenue interests 850 871 886
------------------------------------------------------------------------------------------------------------------------------------
Net productive wells 516.4 534.6 549.6
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Section 29 of the Internal Revenue Code of 1986, as amended, provides an income
tax credit against federal regular income tax liability for sales of certain
fuels produced from nonconventional sources (including natural gas from coal
seams). Fuels qualifying for these credits must be produced from wells drilled
after December 31, 1979, and before January 1, 1993, and must be sold before
January 1, 2003. The credit for natural gas from coal seams is adjusted for
inflation, and the Company estimates that it will approximate $1.06 per Mcf of
qualifying production for calendar year 2000. Accordingly, a significant portion
of the value of proved coalbed methane reserves is associated with this tax
credit.
53
<PAGE> 32
17. INDUSTRY SEGMENT INFORMATION
The Company is principally engaged in two business segments: the purchase,
distribution and sale of natural gas in central and north Alabama (natural gas
distribution) and the acquisition, development, exploration and production of
oil and gas in the continental United States (oil and gas operations). The
accounting policies of the segments are the same as those described in Note 1.
Certain reclassifications have been made to conform the prior years' financial
statements to the current year presentation.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
As of September 30, (in thousands) 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues
Natural gas distribution $ 366,161 $ 325,554 $ 369,940
Oil and gas operations 189,434 171,963 132,687
------------------------------------------------------------------------------------------------------------------------------------
Total $ 555,595 $ 497,517 $ 502,627
------------------------------------------------------------------------------------------------------------------------------------
Operating income (loss)
Natural gas distribution $ 49,063 $ 46,565 $ 41,663
Oil and gas operations 48,358 31,015 20,992
Eliminations and corporate expenses (1,620) (197) (1,170)
------------------------------------------------------------------------------------------------------------------------------------
Total $ 95,801 $ 77,383 $ 61,485
------------------------------------------------------------------------------------------------------------------------------------
Depreciation, depletion and amortization expense
Natural gas distribution $ 28,708 $ 26,730 $ 25,153
Oil and gas operations 58,365 61,885 55,846
------------------------------------------------------------------------------------------------------------------------------------
Total $ 87,073 $ 88,615 $ 80,999
------------------------------------------------------------------------------------------------------------------------------------
Interest expense
Natural gas distribution $ 9,871 $ 10,366 $ 10,221
Oil and gas operations 28,441 27,758 20,130
Eliminations and other (543) (951) (350)
------------------------------------------------------------------------------------------------------------------------------------
Total $ 37,769 $ 37,173 $ 30,001
------------------------------------------------------------------------------------------------------------------------------------
Income tax expense (benefit)
Natural gas distribution $ 14,324 $ 13,163 $ 11,400
Oil and gas operations (7,245) (13,472) (13,896)
Other (290) 444 275
------------------------------------------------------------------------------------------------------------------------------------
Total $ 6,789 $ 135 $ (2,221)
------------------------------------------------------------------------------------------------------------------------------------
Capital expenditures
Natural gas distribution $ 67,073 $ 46,029 $ 54,168
Oil and gas operations 67,090 198,577 120,991
Other 287 53 6
------------------------------------------------------------------------------------------------------------------------------------
Total $ 134,450 $ 244,659 $ 175,165
------------------------------------------------------------------------------------------------------------------------------------
Identifiable assets
Natural gas distribution $ 471,282 $ 410,001 $ 408,149
Oil and gas operations 690,126 604,857 464,214
Eliminations and other 41,633 170,037 121,092
------------------------------------------------------------------------------------------------------------------------------------
Total $ 1,203,041 $ 1,184,895 $ 993,455
------------------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment, net
Natural gas distribution $ 355,248 $ 317,119 $ 324,995
Oil and gas operations 552,287 543,888 431,275
Other 294 100 74
------------------------------------------------------------------------------------------------------------------------------------
Total $ 907,829 $ 861,107 $ 756,344
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
54
<PAGE> 33
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 materially reliable financial information. Reasonable
assurance recognizes that the cost of a system of internal accounting controls
should not exceed the related benefits. This system of internal accounting
controls is augmented by written policies and procedures, internal auditing, and
the careful selection and training of qualified personnel. As of September 30,
2000, 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 five 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.
Geoffrey C. Ketcham
Executive Vice President,
Chief Financial Officer and Treasurer
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Shareholders of Energen:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, shareholders' equity and of cash flows
present fairly, in all material respects, the financial position of Energen
Corporation and Subsidiaries at September 30, 2000 and 1999, and the results of
their operations and their cash flows for the years then ended in conformity
with accounting principles generally accepted in the United States of America.
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 of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Birmingham, Alabama
October 25, 2000
55
<PAGE> 34
SELECTED FINANCIAL AND COMMON STOCK DATA
<TABLE>
<CAPTION>
Energen Corporation
-----------------------------------------------------------------------------------------------------------------
Years ended September 30,
(dollars in thousands, except per share amounts) 2000 1999 1998 1997
-----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
INCOME STATEMENT
Operating revenues $ 555,595 $ 497,517 $ 502,627 $ 448,230
Income before cumulative effect of change
in accounting principle $ 53,018 $ 41,410 $ 36,249 $ 28,997
Net income $ 53,018 $ 41,410 $ 36,249 $ 28,997
Diluted earnings per average common share $ 1.75 $ 1.38 $ 1.23 $ 1.14
Basic earnings per share before cumulative effect $ 1.76 $ 1.40 $ 1.25 $ 1.15
Basic earnings per average common share $ 1.76 $ 1.40 $ 1.25 $ 1.15
-----------------------------------------------------------------------------------------------------------------
BALANCE SHEET
Capitalization at year-end:
Common shareholders' equity $ 400,860 $ 361,504 $ 329,249 $ 301,143
Preferred stock -- -- -- --
Long-term debt 353,932 371,824 372,782 279,602
-----------------------------------------------------------------------------------------------------------------
Total capitalization $ 754,792 $ 733,328 $ 702,031 $ 580,745
-----------------------------------------------------------------------------------------------------------------
Total assets $ 1,203,041 $ 1,184,895 $ 993,455 $ 919,797
-----------------------------------------------------------------------------------------------------------------
Property, plant and equipment, net $ 907,829 $ 861,107 $ 756,344 $ 667,003
-----------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA
Annual dividend rate at year-end $ 0.68 $ 0.66 $ 0.64 $ 0.62
Cash dividends paid per common share $ 0.665 $ 0.645 $ 0.625 $ 0.605
Book value per common share $ 13.24 $ 12.09 $ 11.23 $ 10.46
Market-to-book ratio at year-end (%) 225 167 169 170
Yield at year-end (%) 2.3 3.3 3.4 3.5
Return on average common equity (%) 13.7 11.7 11.1 11.9
Price-to-earnings (diluted) ratio at year-end 17.0 14.7 15.4 15.6
Shares outstanding at year-end (000) 30,278 29,904 29,327 28,796
Price Range:
High $ 30.38 $ 20.38 $ 22.50 $ 18.88
Low $ 14.69 $ 13.13 $ 15.13 $ 11.88
Close $ 29.75 $ 20.25 $ 19.00 $ 17.78
-----------------------------------------------------------------------------------------------------------------
</TABLE>
Note: All information has been adjusted to reflect the 2-for-1 stock split
effective March 2, 1998.
56
<PAGE> 35
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------
1996 1995 1994 1993 1992 1991 1990
--------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
$ 399,442 $ 318,580 $ 374,503 $ 355,878 $ 331,065 $ 324,902 $ 324,022
$ 21,541 $ 19,308 $ 23,751 $ 18,081 $ 15,687 $ 14,112 $ 11,267
$ 21,541 $ 19,308 $ 23,751 $ 18,081 $ 16,628 $ 14,112 $ 11,267
$ 0.97 $ 0.88 $ 1.09 $ 0.88 $ 0.82 $ 0.71 $ 0.58
$ 0.98 $ 0.89 $ 1.10 $ 0.88 $ 0.77 $ 0.71 $ 0.58
$ 0.98 $ 0.89 $ 1.10 $ 0.88 $ 0.82 $ 0.71 $ 0.58
--------------------------------------------------------------------------------------------------
$ 188,405 $ 173,924 $ 167,026 $ 140,313 $ 129,858 $ 121,995 $ 113,316
-- -- -- -- 1,800 1,800 1,800
195,545 131,600 118,302 85,852 90,609 77,677 82,835
--------------------------------------------------------------------------------------------------
$ 383,950 $ 305,524 $ 285,328 $ 226,165 $ 222,267 $ 201,472 $ 197,951
--------------------------------------------------------------------------------------------------
$ 569,410 $ 459,084 $ 411,314 $ 370,685 $ 342,119 $ 337,516 $ 326,350
--------------------------------------------------------------------------------------------------
$ 444,916 $ 327,264 $ 287,182 $ 273,097 $ 254,630 $ 273,539 $ 250,983
--------------------------------------------------------------------------------------------------
$ 0.60 $ 0.58 $ 0.56 $ 0.54 $ 0.52 $ 0.50 $ 0.47
$ 0.585 $ 0.565 $ 0.545 $ 0.525 $ 0.505 $ 0.478 $ 0.448
$ 8.44 $ 7.97 $ 7.65 $ 6.80 $ 6.38 $ 6.04 $ 5.74
142 136 147 182 142 150 157
5.0 5.3 5.0 4.4 5.7 5.5 5.2
11.6 11.0 14.6 13.0 13.0 11.6 10.0
12.4 12.4 10.3 14.1 11.1 12.8 15.5
22,325 21,820 21,836 20,641 20,365 20,209 19,745
$ 12.69 $ 11.75 $ 13.31 $ 13.38 $ 9.44 $ 10.00 $ 10.75
$ 10.69 $ 9.88 $ 9.63 $ 8.81 $ 7.50 $ 8.00 $ 8.00
$ 12.00 $ 10.88 $ 11.25 $ 12.38 $ 9.06 $ 9.06 $ 9.00
--------------------------------------------------------------------------------------------------
</TABLE>
57
<PAGE> 36
SELECTED BUSINESS SEGMENT DATA
<TABLE>
<CAPTION>
Energen Corporation
--------------------------------------------------------------------------------------------------------------
Years ended September 30,
(dollars in thousands) 2000 1999 1998 1997
--------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
NATURAL GAS DISTRIBUTION
Operating revenues
Residential $ 233,839 $ 209,263 $ 241,964 $ 237,022
Commercial and industrial-small 88,521 77,254 89,361 87,477
Commercial and industrial-large -- -- -- --
Transportation 35,312 34,541 35,246 33,080
Other 8,489 4,496 3,369 5,405
--------------------------------------------------------------------------------------------------------------
Total $ 366,161 $ 325,554 $ 369,940 $ 362,984
--------------------------------------------------------------------------------------------------------------
Gas delivery volumes (MMcf)
Residential 26,069 24,751 31,079 28,357
Commercial and industrial-small 12,092 11,662 13,705 12,554
Commercial and industrial-large -- -- -- --
Transportation 70,534 66,356 70,563 65,622
--------------------------------------------------------------------------------------------------------------
Total 108,695 102,769 115,347 106,533
--------------------------------------------------------------------------------------------------------------
Average number of customers
Residential 429,368 425,937 423,602 422,878
Commercial, industrial and transportation 35,526 35,111 34,782 34,485
--------------------------------------------------------------------------------------------------------------
Total 464,894 461,048 458,384 457,363
--------------------------------------------------------------------------------------------------------------
Other data
Depreciation & amortization $ 28,708 $ 26,730 $ 25,153 $ 23,486
Capital expenditures $ 67,073 $ 46,029 $ 54,168 $ 43,277
Operating income $ 49,063 $ 46,565 $ 41,663 $ 38,792
--------------------------------------------------------------------------------------------------------------
OIL AND GAS OPERATIONS
Operating revenues
Natural gas $ 119,680 $ 119,021 $ 97,123 $ 60,228
Oil 41,745 37,227 21,452 13,981
Natural gas liquids 22,914 7,296 7,061 5,772
Other 5,095 8,419 7,051 5,265
--------------------------------------------------------------------------------------------------------------
Total $ 189,434 $ 171,963 $ 132,687 $ 85,246
--------------------------------------------------------------------------------------------------------------
Production volumes
Natural gas (MMcf) 48,084 53,855 43,853 29,318
Oil (MBbl) 2,304 3,122 1,433 775
Natural gas liquids (MBbl) 1,429 762 817 502
--------------------------------------------------------------------------------------------------------------
Proved reserves
Natural gas (MMcf) 777,456 740,001 542,039 544,283
Oil (MBbl) 24,518 24,719 19,845 9,128
Natural gas liquids (MBbl) 26,007 21,937 17,292 12,378
--------------------------------------------------------------------------------------------------------------
</TABLE>
58
<PAGE> 37
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------
1996 1995 1994 1993 1992 1991 1990
--------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
$ 236,583 $194,089 $ 229,019 $ 216,587 $ 198,676 $ 195,250 $ 188,168
87,912 68,409 84,443 83,069 78,799 84,260 85,588
-- 290 790 1,223 6,501 8,916 13,596
30,408 30,490 29,321 27,382 25,089 22,890 22,734
2,349 2,687 1,064 2,299 1,661 (2,188) 873
---------------------------------------------------------------------------------------------------
$ 357,252 $295,965 $ 344,637 $ 330,560 $ 310,726 $ 309,128 $ 310,959
---------------------------------------------------------------------------------------------------
34,963 27,489 31,254 30,957 29,119 26,262 28,653
15,002 12,289 13,536 13,853 13,860 14,837 16,581
-- 29 106 282 2,654 3,411 4,786
61,458 61,640 52,635 49,346 46,235 41,447 39,117
---------------------------------------------------------------------------------------------------
111,423 101,447 97,531 94,438 91,868 85,957 89,137
---------------------------------------------------------------------------------------------------
418,486 410,515 402,531 395,057 387,871 382,747 379,362
34,082 33,163 32,606 32,315 31,773 31,471 31,607
---------------------------------------------------------------------------------------------------
452,568 443,678 435,137 427,372 419,644 414,218 410,969
---------------------------------------------------------------------------------------------------
$ 21,269 $ 19,368 $ 17,941 $ 17,206 $ 17,154 $ 17,126 $ 16,131
$ 43,175 $ 42,780 $ 38,473 $ 22,107 $ 20,228 $ 19,565 $ 19,565
$ 35,270 $ 32,513 $ 30,017 $ 26,381 $ 25,915 $ 25,209 $ 21,080
--------------------------------------------------------------------------------------------------
$ 24,262 $ 14,748 $ 17,292 $ 11,449 $ 10,364 $ 9,889 $ 11,121
10,313 3,765 2,725 3,484 2,559 1,839 1,411
-- -- -- -- -- -- --
7,615 4,100 3,546 2,753 (44) (3,203) (5,927)
--------------------------------------------------------------------------------------------------
$ 42,190 $ 22,613 $ 23,563 $ 17,686 $ 12,879 $ 8,525 $ 6,605
--------------------------------------------------------------------------------------------------
12,308 8,597 9,169 6,245 6,415 5,927 4,954
635 250 191 204 145 88 80
-- -- -- -- -- -- --
--------------------------------------------------------------------------------------------------
212,977 71,267 60,057 67,298 51,329 73,279 57,532
6,315 3,986 1,485 1,289 338 402 330
-- -- -- -- -- -- --
--------------------------------------------------------------------------------------------------
</TABLE>
59
