EX-13 8 g65922ex13.txt FISCAL YEAR 2000 ANNUAL REPORT TO SHAREHOLDERS 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. 23 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.
--------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (dollars in thousands) 2000 1999 1998 --------------------------------------------------------------------------------------------------------------------------------- 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) --------------------------------------------------------------------------------------------------------------------------------- Natural gas transportation and sales margin $ 190,571 $ 181,576 $ 173,538 --------------------------------------------------------------------------------------------------------------------------------- Natural gas sales volumes (MMcf) Residential 26,069 24,751 31,079 Commercial and industrial-small 12,092 11,662 13,705 --------------------------------------------------------------------------------------------------------------------------------- Total natural gas sales volumes 38,161 36,413 44,784 Natural gas transportation volumes (MMcf) 70,534 66,356 70,563 --------------------------------------------------------------------------------------------------------------------------------- Total deliveries (MMcf) 108,695 102,769 115,347 ---------------------------------------------------------------------------------------------------------------------------------
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. 24 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.
--------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (dollars in thousands, except sales price data) 2000 1999 1998 --------------------------------------------------------------------------------------------------------------------------------- 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 --------------------------------------------------------------------------------------------------------------------------------- Total revenues $ 189,434 $ 171,963 $ 132,687 --------------------------------------------------------------------------------------------------------------------------------- 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 --------------------------------------------------------------------------------------------------------------------------------- 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 ---------------------------------------------------------------------------------------------------------------------------------
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. 25 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. 26 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.
------------------------------------------------------------------------------------------------------------------ Years ended September 30, (in thousands) 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------ Capital expenditures for: Renewals, replacements, system expansion and other $ 35,774 $ 26,095 $ 26,806 Support facilities 31,299 19,934 27,362 ------------------------------------------------------------------------------------------------------------------ Total $ 67,073 $ 46,029 $ 54,168 ------------------------------------------------------------------------------------------------------------------
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.
--------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 2000 1999 1998 --------------------------------------------------------------------------------------------------------------------------------- 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 --------------------------------------------------------------------------------------------------------------------------------- Total 71,646 203,293 125,056 Less exploration expenditures charged to income 4,556 4,716 4,065 --------------------------------------------------------------------------------------------------------------------------------- Net capital expenditures $ 67,090 $ 198,577 $ 120,991 ---------------------------------------------------------------------------------------------------------------------------------
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. 27 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 28 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 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*
--------------------------------------------------------------------------------------------------------------------------------- Quarter ended (in dollars) High Low Close Dividends Paid --------------------------------------------------------------------------------------------------------------------------------- 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 ---------------------------------------------------------------------------------------------------------------------------------
* Share prices reflect a 2-for-1 stock split effective March 2, 1998. 30 9 CONSOLIDATED STATEMENTS OF INCOME
Energen Corporation ---------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands, except share data) 2000 1999 1998 ---------------------------------------------------------------------------------------------------------------------------------- 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 ----------------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 31 10 CONSOLIDATED BALANCE SHEETS
Energen Corporation ---------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 2000 1999 ---------------------------------------------------------------------------------------------------------- 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 ----------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 32 11
----------------------------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands, except share data) 2000 1999 ----------------------------------------------------------------------------------------------------------------------------------- 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 -----------------------------------------------------------------------------------------------------------------------------------
33 12 CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
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 --------------------------------------------------------------------------------------------------------------------------------- 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) ---------------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 34 13 CONSOLIDATED STATEMENTS OF CASH FLOW
Energen Corporation --------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 2000 1999 1998 --------------------------------------------------------------------------------------------------------------------------------- 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 ---------------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 35 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 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 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 17 3. LONG-TERM DEBT AND NOTES PAYABLE Long-term debt consists of the following:
--------------------------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 2000 1999 --------------------------------------------------------------------------------------------------------------------------------- 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 ---------------------------------------------------------------------------------------------------------------------------------
The aggregate maturities of long-term debt for the next five years are as follows:
--------------------------------------------------------------------------------------------------------------------------------- Years ending September 30, (in thousands) --------------------------------------------------------------------------------------------------------------------------------- 2001 2002 2003 2004 2005 --------------------------------------------------------------------------------------------------------------------------------- $ 18,648 $ 17,072 $ 15,119 $ 22,145 $ 12,250 ---------------------------------------------------------------------------------------------------------------------------------
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:
--------------------------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 2000 1999 1998 --------------------------------------------------------------------------------------------------------------------------------- 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% ---------------------------------------------------------------------------------------------------------------------------------
Total interest expense for Energen in 2000, 1999 and 1998 was $37,769,000, $37,173,000, and $30,001,000, respectively. 39 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:
--------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 2000 1999 1998 --------------------------------------------------------------------------------------------------------------------------------- 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) ---------------------------------------------------------------------------------------------------------------------------------
Temporary differences and carryforwards which give rise to a significant portion of deferred tax assets and liabilities for 2000 and 1999 are as follows:
--------------------------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 2000 1999 --------------------------------------------------------------------------------------------------------------------------------- Current Noncurrent Current Noncurrent --------------------------------------------------------------------------------------------------------------------------------- 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 ---------------------------------------------------------------------------------------------------------------------------------
40 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:
--------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 2000 1999 1998 --------------------------------------------------------------------------------------------------------------------------------- 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) ---------------------------------------------------------------------------------------------------------------------------------
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:
--------------------------------------------------------------------------------------------------------------------------------- As of June 30, (in thousands) 2000 1999 2000 1999 --------------------------------------------------------------------------------------------------------------------------------- Plan A Plan B --------------------------------------------------------------------------------------------------------------------------------- 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 ---------------------------------------------------------------------------------------------------------------------------------
41 20 The components of net pension expense were:
--------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 2000 1999 1998 2000 1999 1998 --------------------------------------------------------------------------------------------------------------------------------- Plan A Plan B --------------------------------------------------------------------------------------------------------------------------------- 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 ---------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------- As of September 30, 2000 1999 2000 1999 --------------------------------------------------------------------------------------------------------------------------------- Plan A Plan B 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% -- -- ---------------------------------------------------------------------------------------------------------------------------------
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:
--------------------------------------------------------------------------------------------------------------------------------- As of June 30, (in thousands) 2000 1999 2000 1999 --------------------------------------------------------------------------------------------------------------------------------- Salaried Employees Union Employees --------------------------------------------------------------------------------------------------------------------------------- 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 $ -- ---------------------------------------------------------------------------------------------------------------------------------
42 21 Net periodic post-retirement benefit expense included the following:
----------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 2000 1999 1998 2000 1999 1998 ----------------------------------------------------------------------------------------------------------------------------------- Salaried Employees Union Employees ----------------------------------------------------------------------------------------------------------------------------------- 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 ----------------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------------------------- As of September 30, 2000 1999 2000 1999 ----------------------------------------------------------------------------------------------------------------------------------- Salaried Employees Union Employees ----------------------------------------------------------------------------------------------------------------------------------- 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% -----------------------------------------------------------------------------------------------------------------------------------
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 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:
------------------------------------------------------------------------------------------------------------------------------------ 1997 Stock Incentive Plan 1988 Stock Option Plan ------------------------------------------------------------------------------------------------------------------------------------ Weighted Average Weighted Average Shares Exercise Price Shares Exercise Price ------------------------------------------------------------------------------------------------------------------------------------ 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 -- -- -- ------------------------------------------------------------------------------------------------------------------------------------
The following table summarizes information about options outstanding as of September 30, 2000:
------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------ $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 ------------------------------------------------------------------------------------------------------------------------------------
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 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 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:
------------------------------------------------------------------------------------------------------------------------------------ Years ending September 30, (in thousands) ------------------------------------------------------------------------------------------------------------------------------------ 2001 2002 2003 2004 2005 2006 and thereafter ------------------------------------------------------------------------------------------------------------------------------------ $ 3,848 $ 3,859 $ 3,595 $ 3,232 $ 2,818 $ 36,534 ------------------------------------------------------------------------------------------------------------------------------------
9. SUPPLEMENTAL CASH FLOW INFORMATION Supplemental information concerning cash flow activities is as follows:
------------------------------------------------------------------------------------------------------------------------------------ Years ended September 30, (in thousands) 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------
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 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 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.
------------------------------------------------------------------------------------------------------------------------------------ 2000 Fiscal Quarters (in thousands, except per share amounts) First Second Third Fourth ------------------------------------------------------------------------------------------------------------------------------------ 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) ------------------------------------------------------------------------------------------------------------------------------------ 1999 Fiscal Quarters (in thousands, except per share amounts) First Second Third Fourth ------------------------------------------------------------------------------------------------------------------------------------ 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) ------------------------------------------------------------------------------------------------------------------------------------
14. RECONCILIATION OF EARNINGS PER SHARE
------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------
48 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:
------------------------------------------------------------------------------------------------------------------------------------ (in thousands) ------------------------------------------------------------------------------------------------------------------------------------ Oil and gas properties $ 137,533 Less liabilities assumed (13,288) Less cash acquired (429) ------------------------------------------------------------------------------------------------------------------------------------ Acquisition cost, net of cash acquired $ 123,816 ------------------------------------------------------------------------------------------------------------------------------------
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
------------------------------------------------------------------------------------------------------------------------------------ As of September 30, (in thousands) 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------
49 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:
------------------------------------------------------------------------------------------------------------------------------------ Years ended September 30, (in thousands) 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS The following table sets forth results of the Company's oil and gas operations:
------------------------------------------------------------------------------------------------------------------------------------ Years ended September 30, (in thousands) 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------
* 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
------------------------------------------------------------------------------------------------------------------------------------ Years ended September 30, 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------
DRILLING ACTIVITY The following table sets forth the total number of net productive and dry exploratory and development wells drilled:
------------------------------------------------------------------------------------------------------------------------------------ Years ended September 30, 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------
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 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:
------------------------------------------------------------------------------------------------------------------------------------ Gross Net ------------------------------------------------------------------------------------------------------------------------------------ Gas Wells 3,144 1,565 Oil Wells 2,239 514 ------------------------------------------------------------------------------------------------------------------------------------ Developed Acreage 1,000,393 518,349 Undeveloped Acreage 269,425 48,346 ------------------------------------------------------------------------------------------------------------------------------------
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.
------------------------------------------------------------------------------------------------------------------------------------ Year ended September 30, 2000 Gas MMcf Oil MBbl NGL MBbl ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------ Year ended September 30, 1999 Gas MMcf Oil MBb l NGL MBbl ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------ Year ended September 30, 1998 Gas MMcf Oil MBbl NGL MBbl ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------
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 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.
------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------------------------------------------------------
The following are the principal sources of changes in the standardized measure of discounted future net cash flows:
------------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------------------------------------------------------
52 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.
------------------------------------------------------------------------------------------------------------------------------------ Years ended September 30, 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------
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 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.
------------------------------------------------------------------------------------------------------------------------------------ As of September 30, (in thousands) 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------------ 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 ------------------------------------------------------------------------------------------------------------------------------------
54 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 34 SELECTED FINANCIAL AND COMMON STOCK DATA
Energen Corporation ----------------------------------------------------------------------------------------------------------------- Years ended September 30, (dollars in thousands, except per share amounts) 2000 1999 1998 1997 ----------------------------------------------------------------------------------------------------------------- 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 -----------------------------------------------------------------------------------------------------------------
Note: All information has been adjusted to reflect the 2-for-1 stock split effective March 2, 1998. 56 35
-------------------------------------------------------------------------------------------------- 1996 1995 1994 1993 1992 1991 1990 -------------------------------------------------------------------------------------------------- $ 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 --------------------------------------------------------------------------------------------------
57 36 SELECTED BUSINESS SEGMENT DATA
Energen Corporation -------------------------------------------------------------------------------------------------------------- Years ended September 30, (dollars in thousands) 2000 1999 1998 1997 -------------------------------------------------------------------------------------------------------------- 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 --------------------------------------------------------------------------------------------------------------
58 37
-------------------------------------------------------------------------------------------------- 1996 1995 1994 1993 1992 1991 1990 -------------------------------------------------------------------------------------------------- $ 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 -- -- -- -- -- -- -- --------------------------------------------------------------------------------------------------
59