UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE QUARTER ENDED JUNE 30, 2000
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___
Commission IRS Employer
File State of Identification
Number Registrant Incorporation Number
1-7810 Energen Corporation Alabama 63-0757759
2-38960 Alabama Gas Corporation Alabama 63-0022000
605 Richard Arrington, Jr. Boulevard North
Birmingham, Alabama 35203-2707
Telephone Number 205/326-2700
http://www.energen.com
Alabama Gas Corporation, a wholly owned subsidiary of Energen Corporation, meets
the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and
is therefore filing this Form with reduced disclosure format pursuant to General
Instruction H(2).
Indicate by a check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities and Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. YES X NO ____
Indicate the number of shares outstanding of each of the issuers' classes of
common stock, as of August 11, 2000:
Energen Corporation, $0.01 par value 30,170,424 shares
Alabama Gas Corporation, $0.01 par value 1,972,052 shares
<PAGE> 1
ENERGEN CORPORATION AND ALABAMA GAS CORPORATION
FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2000
TABLE OF CONTENTS
Page
PART I: FINANCIAL INFORMATION (Unaudited)
Item 1. Financial Statements
(a) Consolidated Statements of Income of Energen Corporation 3
(b) Consolidated Balance Sheets of Energen Corporation 4
(c) Consolidated Statements of Cash Flows of Energen Corporation 6
(d) Statements of Income of Alabama Gas Corporation 7
(e) Balance Sheets of Alabama Gas Corporation 8
(f) Statements of Cash Flows of Alabama Gas Corporation 10
(g) Notes to Unaudited Financial Statements 11
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 15
Selected Segment Data of Energen Corporation 20
Item 3. Quantitative and Qualitative Disclosures about Market Risk 21
PART II: OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K 22
SIGNATURES 23
<PAGE> 2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
Three months ended Nine months ended
June 30, June 30,
(in thousands, 2000 1999 2000 1999
except share data)
Operating Revenues
Natural gas distribution $69,111 $63,296 $313,085 $279,545
Oil and gas operations 47,456 45,224 139,947 131,333
Total operating revenues 116,567 108,520 453,032 410,878
Operating Expenses
Cost of gas 26,042 22,475 133,960 109,053
Operations and maintenance 42,540 42,133 126,404 127,591
Depreciatin, depletion and
amortization 24,210 22,156 66,947 67,803
Taxes, other than
income taxes 10,617 8,354 36,805 29,289
Total operating expenses 103,409 95,118 364,116 333,736
Operating Income 13,158 13,402 88,916 77,142
Other Income (Expense)
Interest expense (9,368) (8,930) (28,053) (28,135)
Other, net 365 476 1,138 990
Total other expense (9,003) (8,454) (26,915) (27,145)
Income Before Income Taxes 4,155 4,948 62,001 49,997
Income tax (benefit) expense (303) 1,435 7,241 273
Net Income $ 4,458 $ 3,513 $ 54,760 $49,724
Basic Earnings Per Avg.
Common Share $ 0.15 $ 0.12 $ 1.82 $ 1.68
Diluted Earnings Per Avg.
Common Share $ 0.15 $ 0.12 $ 1.81 $ 1.66
Dividends Per
Common Share $ 0.165 $ 0.16 $ 0.495 $ 0.48
Basic Avg. Commmon
Shares Outstanding 30,081 29,720 30,081 29,581
Diluted Avg. Common
Shares Outstanding 30,346 30,015 30,315 29,877
The accompanying Notes are an integral part of these financial statements.
<PAGE> 3
CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
June 30, 2000 September 30, 1999
(in thousands) (Unaudited)
ASSETS
Current Assets
Cash and cash equivalents $ 10,716 $145,390
Accounts receivable, net of
allowance for doubtful
accounts of $6,303 at June 30, 2000,
and $5,598 at September 30, 1999 94,374 74,505
Inventories, at average cost
Storage gas inventory 30,575 24,722
Materials and supplies 9,083 8,287
Liquified natural gas in storage 3,236 3,318
Deferred gas costs 3,468 2,305
Deferred income taxes 18,292 14,691
Prepayments and other 78,743 22,529
Total current assets 248,487 295,747
Property, Plant and Equipment
Oil and gas properties,
successful efforts method 704,202 669,985
Less accumulated depreciation,
depletion and amortization 168,955 129,839
Oil and gas properties, net 535,247 540,146
Utility plant 683,591 645,596
Less accumulated depreciation 347,421 328,775
Utility plant, net 336,170 316,821
Other property, net 4,669 4,140
Total property, plant and
equipment, net 876,086 861,107
Other Assets
Deferred income taxes 26,196 21,055
Deferred charges and other 11,304 6,986
Total other assets 37,500 28,041
TOTAL ASSETS $1,162,073 $1,184,895
The accompanying Notes are an integral part of these financial statements.
<PAGE> 4
CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
June 30, 2000 September 30, 1999
(in thousands, except share data) (Unaudited)
CAPITAL AND LIABILITIES
Current Liabilities
Long-term debt due within one year $ 6,648 $ 1,955
Notes payable to banks 147,000 268,000
Accounts payable 118,840 61,418
Accrued taxes 30,935 22,247
Customers' deposits 16,403 16,301
Amounts due customers 11,239 18,576
Accrued wages and benefits 20,708 19,404
Other 34,355 37,381
Total current liabilities 386,128 445,282
Deferred Credits and Other Liabilities
Other 5,156 6,285
Total deferred credits and
other liabilities 5,156 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,
30,272,570 shares outstanding
at June 30, 2000, and
29,903,964 shares outstanding
at September 30, 1999 303 299
Premium on capital stock 212,134 205,831
Capital surplus 2,802 2,802
Retained earnings 192,435 152,572
Deferred compensation plan 3,606 2,054
Treasury stock, at cost (329,578
shares at June 30, 2000,
and 101,431 shares at
September 30, 1999) (6,479) (2,054)
Total common shareholders' equity 404,801 361,504
Long-term debt 365,988 371,824
Total capitalization 770,789 733,328
TOTAL CAPITAL AND LIABILITIES $1,162,073 $1,184,895
The accompanying Notes are an integral part of these financial statements.
<PAGE> 5
CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Nine months ended June 30, (in thousands) 2000 1999
Operating Activities
Net income $54,760 $49,724
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization 66,947 67,803
Deferred income taxes, net (9,173) (11,644)
Deferred investment tax credits, net (336) (336)
Gain on sale of assets (1,472) (2,900)
Net change in:
Accounts receivable (19,869) 3,298
Inventories (6,567) (900)
Deferred gas cost (1,163) (111)
Accounts payable (1,169) (8,667)
Other current assets and liabilities 2,108 16,263
Other, net (5,309) 819
Net cash provided by operating
activities 78,757 113,349
Investing Activities
Additions to property, plant
and equipment (81,614) (85,339)
Acquisition, net of cash acquired -- (123,816)
Proceeds from sale of assets 2,600 48,331
Other, net (807) (675)
Net cash used in investing activities (79,821) (161,499)
Financing Activities
Payment of dividends on common stock (14,896) (14,197)
Issuance of common stock 6,664 8,222
Purchase of treasury stock (3,231) (442)
Reduction of long-term debt (1,147) (6,219)
Payment of note payable issued
to purchase U.S. Treasury securities (140,917) (100,571)
Net change in short-term debt 19,917 62,571
Net cash used in financing activities (133,610) (50,636)
Net change in cash and cash equivalents (134,674) (98,786)
Cash and cash equivalents at
beginning of period 145,390 103,231
Cash and Cash Equivalents at
End of Period $10,716 $ 4,445
The accompanying Notes are an integral part of these financial statements.
<PAGE> 6
STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
Three months ended Nine months ended
June 30, June 30,
(in thousands) 2000 1999 2000 1999
Operating Revenues $69,111 $63,296 $313,085 $279,545
Operating Expenses
Cost of gas 26,439 22,868 135,190 110,426
Operations and maintenance 26,236 25,597 77,131 75,400
Depreciation 7,243 6,693 21,380 19,886
Income taxes
Current 1,207 2,045 21,946 20,438
Deferred, net (743) (1,700) (3,869) (3,671)
Deferred investment tax
credits, net (112) (112) (336) (336)
Taxes, other than
income taxes 5,906 5,292 23,535 21,052
Total operating expenses 66,176 60,683 274,977 243,195
Operating Income 2,935 2,613 38,108 36,350
Other Income (Expense)
Allowance for funds used
during construction 365 159 681 327
Other, net 262 195 365 (288)
Total other income 627 354 1,046 39
Interest Charges
Interest on long-term debt 2,135 2,135 6,406 6,477
Other interest expense 311 325 957 1,352
Total interest charges 2,446 2,460 7,363 7,829
Net Income $1,116 $ 507 $31,791 $28,560
The accompanying Notes are an integral part of these financial statements.
<PAGE> 7
BALANCE SHEETS
ALABAMA GAS CORPORATION
June 30, 2000 September 30, 1999
(in thousands) (Unaudited)
ASSETS
Property, Plant and Equipment
Utility plant $683,591 $645,596
Less accumulated depreciation 347,421 328,775
Utility plant, net 336,170 316,821
Other property, net 250 298
Current Assets
Cash and cash equivalents 3,863 533
Accounts receivable
Gas 56,841 37,157
Merchandise 2,119 2,283
Affiliated companies 12,392 20,654
Other 1,859 1,966
Allowance for doubtful accounts (5,032) (4,532)
Inventories, at average cost
Storage gas inventory 30,575 24,722
Materials and supplies 5,461 5,024
Liquified natural gas in storage 3,236 3,318
Deferred gas costs 3,468 2,305
Deferred income taxes 14,596 11,621
Prepayments and other 2,383 4,652
Total current assets 131,761 109,703
Deferred Charges and Other Assets 4,775 3,833
TOTAL ASSETS $472,956 $430,655
The accompanying Notes are an integral part of these financial statements.
<PAGE> 8
BALANCE SHEETS
ALABAMA GAS CORPORATION
June 30, 2000 September 30, 1999
(in thousands, except share data) (Unaudited)
CAPITAL AND LIABILITIES
Capitalization
Common shareholder's equity
Common stock, $0.01 par value;
3,000,000 shares authorized,
1,972,052 shares outstanding at
June 30, 2000, and
September 30, 1999 $ 20 $ 20
Premium on capital stock 31,682 31,682
Capital surplus 2,802 2,802
Retained earnings 175,291 143,502
Total common shareholder's equity 209,795 178,006
Preferred stock, cumulative $0.01
par value, 120,000 shares authorized,
issuable in series-$4.70 Series -- --
Long-term debt 115,000 119,650
Total capitalization 324,795 297,656
Current Liabilities
Long-term debt due within one year 4,650 --
Accounts payable 45,901 36,985
Accrued taxes 29,180 18,799
Customers' deposits 16,403 16,301
Other amounts due customers 11,239 18,576
Accrued wages and benefits 11,602 9,663
Other 8,833 10,847
Total current liabilities 127,808 111,171
Deferred Credits and Other Liabilities
Deferred income taxes 16,324 16,689
Accumulated deferred investment
tax credits 1,877 2,213
Regulatory liability 1,349 2,112
Customer advances for construction
and other 803 814
Total deferred credits and
other liabilities 20,353 21,828
Commitments and Contingencies -- --
TOTAL CAPITAL AND LIABILITIES $472,956 $430,655
The accompanying Notes are an integral part of these financial statements.
<PAGE> 9
STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Nine months ended June 30, (in thousands) 2000 1999
Operating Activities
Net income $ 31,791 $28,560
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization 21,380 19,886
Deferred income taxes, net (3,869) (3,671)
Deferred investment tax credits (336) (336)
Net change in:
Accounts receivable (18,913) (304)
Inventories (6,208) (1,443)
Deferred gas costs (1,163) (111)
Accounts payable 8,916 5,175
Other current assets and liabilities 4,547 12,233
Other, net (1,077) 62
Net cash provided by operating activities 35,068 60,051
Investing Activities
Additions to property, plant and equipment (40,018) (31,961)
Net advances from (to) affiliates 8,262 (32,125)
Proceeds from sale of assets -- 27,000
Other, net 18 479
Net cash used in investing activities (31,738) (36,607)
Financing Activities
Net change in short-term debt -- (20,350)
Net cash used in financing activities -- (20,350)
Net change in cash and cash equivalents 3,330 3,094
Cash and cash equivalents at
beginning of period 533 1,222
Cash and Cash Equivalents at
End of Period $ 3,863 $ 4,316
The accompanying Notes are an integral part of these financial statements.
<PAGE> 10
NOTES TO UNAUDITED FINANCIAL STATEMENTS
ENERGEN CORPORATION AND ALABAMA GAS CORPORATION
1. BASIS OF PRESENTATION
All adjustments to the unaudited financial statements which are, in the opinion
of management, necessary for a fair statement of the results of operations for
the interim periods have been recorded. Such adjustments consisted of normal
recurring items. The consolidated financial statements and notes should be read
in conjunction with the financial statements and notes thereto for the years
ended September 30, 1999, 1998, and 1997, included in the 1999 Annual Report of
Energen Corporation (the Company) on Form 10-K. Certain reclassifications were
made to conform prior years' financial statements to the current-quarter
presentation. The Company?s natural gas distribution business is seasonal in
character and influenced by weather conditions. Results of operations for the
interim periods are not necessarily indicative of the results which may be
expected for the fiscal year.
2. REGULATORY
As an Alabama utility, Alabama Gas Corporation (Alagasco) is subject to
regulation by the Alabama Public Service Commission (APSC), which established
the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. 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 average 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 year-end equity upon which a return is permitted to 60
percent of total capitalization and provides for certain cost control measures
designed to monitor Alagasco's operations and maintenance (O&M) expense. If the
change in O&M expense per customer falls within 1.25 percentage points above or
below the Consumer Price Index For All Urban Customers (index range), no
adjustment is required. If 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.
Alagasco calculates a temperature adjustment to customers? bills to remove the
effect of departures from normal temperatures on earnings. The calculation is
performed monthly, and the adjustments to customers' bills are made in the same
billing cycle in which the weather variations occur. 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; and (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 ESR reserve on October 6, 1998, in the
amount of $3.9 million; the maximum approved funding level 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. The APSC will re-evaluate the operation of the ESR
following the conclusion of Alagasco's fiscal year 2000.
In accordance with APSC-directed regulatory accounting procedures, Alagasco in
1989 began returning to customers excess utility deferred taxes which resulted
from a reduction in the federal statutory tax rate from 46 percent to 34 percent
using the average rate assumption method. This method provides for the return to
ratepayers of excess deferred taxes over the lives of the related assets. In
1993 those excess taxes were reduced as a result of a federal tax rate increase
from 34 percent to 35 percent. Remaining excess utility deferred taxes of $1.3
million are being returned to ratepayers over approximately 11 years. At June
30, 2000, and September 30, 1999, a regulatory liability related to income taxes
of $1.3 million and $2.1 million, respectively, was included in the consolidated
financial statements.
As of November 1, 1998, Alagasco offered a Voluntary Early Retirement Program to
certain eligible employees. The APSC allowed these costs to be amortized over a
three-year period. As of June 30, 2000, and September 30, 1999, a regulatory
asset of $1.5 million and $2.4 million, respectively, was included in the
consolidated financial statements for costs associated with this early
retirement program.
3. DERIVATIVE COMMODITY INSTRUMENTS
Energen Resources Corporation, Energen?s oil and gas subsidiary, periodically
enters into derivative commodity instruments to hedge its exposure to price
fluctuations on oil and gas production. Such instruments include regulated
natural gas and crude oil futures contracts traded on the New York Mercantile
Exchange and over-the-counter swaps and basis hedges with major energy
derivative product specialists. These transactions are accounted for under the
hedge method of accounting. Under this method, any unrealized gains and losses
are recorded as a current receivable/payable with a corresponding deferred
gain/loss. Realized gains and losses are deferred as current 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 deferred losses of
$75.1 million and $16.5 million included in prepayments and other on the balance
sheet as of June 30, 2000, and September 30, 1999, respectively.
Energen Resources had entered into contracts and swaps as of June 30, 2000 for
9.9 Bcf of its remaining fiscal 2000 gas production at an average contract price
of $2.44 per Mcf and for 480 MBbl of its remaining oil production at an average
contract price of $19.74 per barrel. In addition, the Company had hedged the
basis difference on 3.0 Bcf of its remaining fiscal 2000 San Juan Basin gas
production.
As of June 30, 2000, fiscal year 2001 contracts and swaps were in place for 37
Bcf of gas production at an average contract price of $2.76 per Mcf and for 750
MBbl of oil production at an average contract price of $23.39 per barrel. The
Company also had hedged 150 MBbl of oil production with a collar price of $20.00
to $25.24 per barrel. In addition, the Company had hedged the basis difference
on 9.6 Bcf of its fiscal 2001 San Juan Basin gas production. Fiscal year 2002
contracts and swaps were in place for 4.8 Bcf of gas production hedged at an
average contract price of $2.98 per Mcf.
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. Management uses the historic relationships
between the derivative instruments and the sales prices of the hedged volumes to
ensure that a high level of correlation exists.
4. RECENT PRONOUNCEMENTS OF THE FASB
In June 1998, the FASB issued Statement of Financial Accounting Standards (SFAS)
No. 133 (subsequently amended by SFAS Nos. 137 and 138), Accounting for
Derivative Instruments and Hedging Activities, which established new accounting
and reporting standards for derivative instruments. The Company is required to
adopt this statement in fiscal year 2001. 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/loss on the
derivative instrument is 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 immediately
recognized in earnings. The Company currently is evaluating the potential impact
to earnings of derivatives not effective in achieving offsets in fair values of
the hedged items due to changes in anticipated basis differentials or other
factors. The Company may enter into additional derivative contracts (e.g. basis
swaps) to help minimize the earnings impact, however, this may not fully
eliminate potential earnings volatility to the Company.
5. SEGMENT INFORMATION
The Company principally is 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).
Three months ended Nine months ended
June 30, June 30,
(in thousands) 2000 1999 2000 1999
Operating revenues
Natural gas distribution $69,111 $63,296 $313,085 $279,545
Oil and gas operations 47,456 45,224 139,947 131,333
Total $116,567 $108,520 $453,032 $410,878
Operating income (loss)
Natural gas distribution $3,287 $ 2,846 $55,849 $52,781
Oil and gas operations 10,469 11,070 34,279 25,141
Eliminations and
corporate expenses (598) (514) (1,212) (780)
Total $13,158 $13,402 $88,916 $77,142
Identifiable assets
Natural gas distribution $460,564 $430,244 $460,564 $430,244
Oil and gas operations 709,455 627,231 709,455 627,231
Eliminations and other (7,946) (47,276) (7,946) (47,276)
Total $1,162,073 $1,010,199 $1,162,073 $1,010,199
6. ACCOUNTING FOR LONG-LIVED ASSETS
Statement of Financial Accounting Standards (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.
7. RECONCILIATION OF EARNINGS PER SHARE
(in thousands, except Three months ended Three months ended
per share amounts) June 30, 2000 June 30, 1999
Per Share Per Share
Income Shares Amount Income Shares Amount
Basic EPS $4,458 30,081 $ 0.15 $3,513 29,720 $0.12
Effect of Dilutive Securities
Long-range performance shares 134 148
Non-qualified stock options 118 147
Restricted stock 13 --
Diluted EPS $4,458 30,346 $ 0.15 $3,513 30,015 $0.12
(in thousands, except Nine months ended Nine months ended
per share amounts) June 30, 2000 June 30, 1999
Per Share Per Share
Income Shares Amount Income Shares Amount
Basic EPS $54,760 30,081 $ 1.82 $49,724 29,581 $1.68
Effect of Dilutive Securities
Long-range performance shares 129 148
Non-qualified stock options 92 148
Restricted stock 13 --
Diluted EPS $54,760 30,315 $ 1.81 $49,724 29,877 $1.66
<PAGE> 14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Energen's net income totaled $4.5 million ($0.15 per diluted share) for the
three months ended June 30, 2000, compared to net income of $3.5 million ($0.12
per diluted share) recorded in the same period last year. Energen Resources
Corporation, Energen's oil and gas subsidiary, realized net income of $3.8
million in the current fiscal quarter as compared with $3.1 million in the same
period last year. Energen Resources benefited from significantly higher realized
sales prices for oil, natural gas and natural gas liquids, as well as increased
tax credits due to the timing of recognition on an interim basis and to
adjustments to prior-year tax credit estimates. Negatively affecting net income
were reduced production levels primarily resulting from the June 1999 sale of
certain offshore Gulf of Mexico properties and a $2.2 million ($0.07 per diluted
share) after-tax writedown under Statement of Financial Accounting Standards
(SFAS) No. 121. Prior-period earnings included a $1.9 million ($0.06 per diluted
share) after-tax gain on the sale of the offshore properties. Energen's natural
gas utility, Alagasco, contributed net income of $1.1 million in the third
quarter. This compares with $0.5 million of net income in the same period last
year and 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.
For the 2000 fiscal year-to-date, Energen's net income totaled $54.8 million
($1.81 per diluted share) compared with $49.7 million ($1.66 per diluted share)
for the same period in the prior year. Energen Resources' net income totaled
$23.5 million and compared favorably with $21 million of net income for the
first nine months of fiscal 1999. Higher realized commodity prices more than
offset lower production levels, lower tax credits largely due to the timing of
recognition on an interim basis, and the SFAS No. 121 writedown in the current-
year third quarter. Alagasco's earnings increased $3.2 million in the current
year-to-date to $31.8 million as the utility continued to earn its allowed range
of return on an increased level of equity.
Natural Gas Distribution
Natural gas distribution revenues increased $5.8 million for the quarter and
$33.5 million on a year-to-date basis primarily due to an increase in the
commodity cost of gas, which is recovered from customers through the Gas Supply
Adjustment (GSA) rider. Increased sales volumes also affected the year-to-date
increase in revenues. For the quarter, weather that was 2.5 percent warmer than
the same period last year contributed to a 3.5 percent decrease in residential
sales volumes and a 3.4 percent decrease in small commercial and industrial
customer sales volumes. The addition of a cogeneration facility and increased
volumes to a power generation facility largely contributed to an 18.5 percent
increase in transportation volumes. For the year-to-date, weather that was 12.8
percent colder than the same period last year contributed to a 6.2 percent
increase in residential sales volumes and a 4.9 percent increase in small
commercial and industrial customers. For the same reason that influenced the
quarter, transportation customers had a 13.9 percent increase in throughput.
Higher commodity gas prices contributed to a 15.6 percent increase in cost of
gas for the quarter, while higher gas prices along with increased gas purchase
volumes contributed to the 22.4 percent increase in cost of gas for the year-to-
date. Alagasco calculates a temperature adjustment to certain customers' bills
on a real-time basis to substantially remove the effect of departures from
normal temperatures on Alagasco's earnings. The customers to whom the
temperature adjustment applies primarily are residential, small commercial and
small industrial.
As discussed more fully in Note 2, Alagasco is subject to regulation by the
APSC. On October 7, 1996, the APSC issued an order extending the Company?s
current rate-setting mechanism 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.
Operations and maintenance (O&M) expense increased slightly in both the current
quarter and year-to-date periods primarily due to increased labor related costs
partially offset by reduced general liability insurance expense.
A slight increase in depreciation expense in the current quarter and year-to-
date primarily was due to normal growth of the utility?s distribution system.
Taxes other than income primarily reflected various state and local business
taxes as well as payroll-related taxes. State and local business taxes generally
are based on gross receipts and fluctuate accordingly.
Oil and Gas Operations
Revenues from oil and gas operations rose 4.9 percent to $47.5 million for the
three months ended June 30, 2000, and 6.6 percent to $139.9 million for the
year-to-date largely as a result of the significantly higher commodity prices
more than offsetting reduced production. For the quarter, realized gas prices
increased 19.4 percent to $2.58 per Mcf, while realized oil prices increased 59
percent to $20.21 per barrel. Natural gas liquids prices increased 68.7 percent
to an average price of $15.84 per barrel. For the year-to-date, realized gas
prices increased 9.9 percent to $2.44 per Mcf, realized oil prices increased
50.8 percent to $17.55 per barrel and natural gas liquids prices increased 83.9
percent to an average price of $15.26 per barrel.
Natural gas production in the third fiscal quarter decreased 14 percent to 11.5
Bcf and oil volumes declined 32.3 percent to 526 MBbl primarily due to property
sales occurring during the latter half of the prior fiscal year. Production of
natural gas liquids increased 34.6 percent to 342 MBbl as a result of higher
liquids prices, which led to substantially all natural gas liquids being removed
from the gas stream during processing. For the year-to-date, natural gas
production decreased 13 percent to 36.6 Bcf, oil volumes decreased 28.3 percent
to 1,729 MBbl, and natural gas liquids production increased 90.8 percent to
1,036 MBbl primarily for the same reasons as indicated above. Natural gas
comprised approximately 69 percent of Energen Resources' production for the
current quarter and the year-to-date.
Energen Resources enters into derivative commodity instruments to hedge its
exposure to the impact of price fluctuations on oil and gas production. Such
instruments include regulated natural gas and crude oil futures contracts traded
on the New York Mercantile Exchange 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. At June 30, 2000,
Energen Resources had entered into contracts and swaps for 9.9 Bcf of its
remaining fiscal 2000 gas production at an average contract price of $2.44 per
Mcf and for 480 MBbl of its remaining oil production at an average contract
price of $19.74 per barrel. In addition, the Company had hedged the basis
difference on 3.0 Bcf of its remaining fiscal 2000 San Juan Basin gas
production.
As of June 30, 2000, fiscal year 2001 contracts and swaps were in place for 37
Bcf of gas production at an average contract price of $2.76 per Mcf and for 750
MBbl of oil production at an average contract price of $23.39 per barrel. The
Company also had hedged 150 MBbl of oil production with a collar price of $20.00
to $25.24 per barrel. In addition, the Company had hedged the basis difference
on 9.6 Bcf of its fiscal 2001 San Juan Basin gas production. Fiscal year 2002
contracts and swaps were in place for 4.8 Bcf of gas production hedged at an
average contract price of $2.98 per Mcf.
In addition to the derivatives described above, the Company has three-way
pricing, physical sales contracts in place for approximately 22 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 $0.25-$0.45, depending on the contracts. In fiscal year 2003, the
Company has three-way pricing, physical sales contracts in place for
approximately 16 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 $0.25-$0.45, depending on the contracts.
Energen Resources, in the ordinary course of business, may be involved in the
sale of developed and undeveloped non-strategic properties. Gains or losses on
the sale of such properties are included in operating revenues. Energen
Resources recorded a pre-tax gain of $743,000 for the current quarter as
compared to $3.1 million in the prior fiscal quarter and a gain of $1.5 million
year-to-date as compared to $3.1 million in the same period last year on the
sale of various properties. The largest of several property sales occurred in
June 1999 when Energen Resources recorded a $3.0 million pre-tax gain on the
sale of offshore Gulf of Mexico properties.
O&M expense decreased $316,000 for the quarter and $3.4 million for the year-to-
date. Lease operating expenses decreased by $1.3 million for the quarter and
$4.9 million for the year-to-date primarily due to the sale of the offshore
properties. Exploration expense remained stable for the quarter and was $0.4
million higher in the year-to-date primarily due to slightly increased
exploratory efforts over the prior-year.
The SFAS No. 121 pretax writedown of $3.5 million, caused by a downward reserve
revision on a small oil and gas field, was recorded as increased depreciation,
depletion and amortization (DD&A) expense in the current-year third quarter. A
$1.5 million increase in DD&A for the quarter resulted from the writedown,
partially offset by lower production volumes. For the year-to-date, DD&A
decreased $2.4 million, as decreased production more than offset the SFAS No.
121 writedown. The average depletion rate for the quarter of $0.79, excluding
the effect of the writedown, remained stable as compared to $0.78 for the same
period last year. For the year-to-date, the average depletion rate was $0.78 as
compared to $0.79 in the prior fiscal period.
Energen Resources' expense for taxes other than income taxes primarily reflected
production-related taxes which were $1.5 million higher this quarter and $5.1
million higher for the year-to-date as a result of the increase in the market
prices of natural gas, oil and natural gas liquids.
Non-Operating Items
Interest expense for the Company remained relatively stable in quarter and year-
to-date comparisons. The Company's average borrowings under its short-term
credit facilities increased slightly.
The Company's effective tax rates are 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. These
credits 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 through fiscal year 2003.
Income tax expense decreased in quarter comparisons as a result of lower
consolidated pretax income and higher nonconventional fuels tax credits of $1.2
million primarily due to timing of the recognition on an interim basis and to
adjustments to prior-year tax credit estimates. In year-to-date comparisons,
income tax expense increased as a result of higher consolidated pretax income
and lower nonconventional fuels tax credits of $3.0 million, largely due to the
timing of the recognition on an interim basis. The estimated effective tax rate
utilized in computing year-to-date income tax expense reflects an expected
financial recognition of $14 million of nonconventional fuels tax credits for
fiscal year 2000.
FINANCIAL POSITION AND LIQUIDITY
Cash flows from operations for the current year-to-date were $78.8 million as
compared to $113.3 million in the same period in the prior year. Net income
increased during the period but was more than offset by changes in working
capital items, which are highly influenced by throughput, oil and gas production
volumes and timing of payments.
The Company had a net investment of $79.8 million through the nine months ended
June 30, 2000, primarily in the addition of property, plant and equipment.
Energen Resources invested $41.3 million in capital expenditures year-to-date
primarily related to the development of oil and gas properties. Utility capital
expenditures totaled $40.9 million year-to-date and represented system
distribution expansion and support facilities.
The Company used $133.6 million year-to-date for financing activities. For tax
planning purposes, the Company borrowed $140.9 million in September 1999 to
invest in short-term federal obligations. The Treasuries matured in early
October 1999 and the proceeds were used to repay the debt. Borrowings under
Energen's short-term credit facilities increased slightly.
FUTURE CAPITAL RESOURCES AND LIQUIDITY
The Company plans to continue to implement its diversified growth strategy. This
strategy focuses on expanding Energen Resources' oil and gas operations through
the acquisition and exploitation of producing properties with developmental
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 growth in earnings per diluted share (EPS) of 10
percent a year over each rolling five-year period. For the five fiscal years
ending September 30, 2000, Energen expects to have generated compound EPS growth
of more than 13 percent a year.
The Company's management recently reevaluated Energen's capital spending and
financing plans in light of historically high commodity prices for natural gas,
oil and natural gas liquids. 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. As a
result, Energen's management now plans to utilize these commodity price-driven
increases in cash flows to help pay down debt incurred to finance Energen
Resources' acquisition and exploitation strategy rather than seek near-term
refinancing in the secondary equity market, as previously planned.
In addition, the Company is no longer actively pursuing its targeted $50 million
in acquisitions during fiscal year 2000. Energen Resources' capital spending
plans during fiscal year 2001 are for $50 million to be invested in the
acquisition of producing properties with development potential and another $50
million to be invested in exploitation activities and limited exploration and
related development. Over the five-year period ending in fiscal year 2005,
Energen plans to invest between $850 million and $900 million for proved
property acquisitions, exploitation activities and limited exploration and
related development. To finance Energen Resources' acquisition and exploitation
program, the Company plans to continue to utilize its short-term credit
facilities as needed to supplement internally generated cash flows. During
fiscal year 1999, Energen increased its available short-term credit facilities
to $249 million.
Energen Resources' continued ability to invest in property acquisitions may be
influenced by industry trends, including the historically cyclical nature of the
producing property acquisition market. From time to time, Energen Resources also
may be engaged in negotiations to sell, trade or otherwise dispose of previously
acquired property.
During fiscal year 2000, Alagasco plans to invest approximately $65 million in
capital expenditures for normal distribution and support systems and to replace
liquifaction equipment at one of its two liquified natural gas facilities.
Alagasco also maintains an investment in storage gas which is expected to
average approximately $27 million in 2000. The utility anticipates funding
capital requirements through internally generated capital and the utilization of
short-term credit facilities.
Forward-Looking Statements and Risks
Certain statements in this report, including statements of future plans,
objectives and expected performance of the Company and its subsidiaries, are
forward-looking statements that are dependent on certain events, risks and
uncertainties that may be outside the Company's control and 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 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 risk including that related to
timing, success rates and cost overruns. These risks can be affected by lease
and rig availability, complex geology and other factors. Although Energen
Resources makes use of futures, swaps and fixed price contracts to mitigate
risk, fluctuations in future oil and gas prices could materially affect the
Company's financial position and results of operations and, furthermore, such
risk mitigation activities may cause the Company's financial position and
results of operations to be materially different from results which would have
been obtained had such risk mitigation activities not occurred.
OTHER
Recent Pronouncements of the FASB
In June 1998, the FASB issued SFAS No. 133 (subsequently amended by SFAS Nos.
137 and 138), Accounting for Derivative Instruments and Hedging Activities,
which established new accounting and reporting standards for derivative
instruments. The Company is required to adopt this statement in fiscal year
2001. 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/loss on the derivative instrument is 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 immediately recognized in earnings. The Company
currently is evaluating the potential impact to earnings of derivatives not
effective in achieving offsets in fair values of the hedged items due to changes
in anticipated basis differentials or other factors. The Company may enter into
additional derivative contracts (e.g. basis swaps) to help minimize the earnings
impact, however, this may not fully eliminate potential earnings volatility to
the Company.
<PAGE> 19
SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
Three months ended Nine months ended
(in thousands, except June 30, June 30,
sales price data) 2000 1999 2000 1999
Natural Gas Distribution
Operating revenues
Residential $42,684 $39,406 $205,540 $183,970
Commercial and
industrial - small 16,560 14,915 74,629 65,752
Transportation 8,245 7,814 28,302 26,901
Other 1,622 1,161 4,614 2,922
Total $69,111 $63,296 $313,085 $279,545
Gas delivery volumes (MMcf)
Residential 4,261 4,414 24,028 22,619
Commercial and
industrial - small 2,232 2,311 10,531 10,043
Transportation 18,145 15,312 52,493 46,071
Total 24,638 22,037 87,052 78,733
Other data
Depreciation and
amortization $ 7,243 $ 6,693 $ 21,380 $ 19,886
Capital expenditures $16,267 $ 12,327 $ 40,882 $ 31,961
Operating income $ 3,287 $ 2,846 $ 55,849 $ 52,781
Oil and Gas Operations
Operating revenues
Natural gas $29,764 $28,896 $ 89,332 $ 93,323
Oil 10,639 9,879 30,356 28,074
Natural gas liquids 5,414 2,388 15,808 4,504
Other 1,639 4,061 4,451 5,432
Total $47,456 $45,224 $139,947 $131,333
Sales volume
Natural gas (MMcf) 11,521 13,404 36,629 42,117
Oil (MBbl) 526 777 1,729 2,412
Natural gas liquids (MBbl) 342 254 1,036 543
Average sales price
Natural gas (Mcf) $ 2.58 $ 2.16 $ 2.44 $ 2.22
Oil (barrel) $20.21 $ 12.71 $ 17.55 $11.64
Natural gas
liquids (barrel) $15.84 $ 9.39 $ 15.26 $ 8.30
Other data
Depreciation, depletion
and amortization $16,967 $15,463 $45,567 $ 47,917
Capital expenditures $14,804 $18,432 $41,291 $177,179
Exploration expenditures $ 969 $ 1,055 $ 3,523 $ 3,144
Operating income $10,469 $11,070 $34,279 $ 25,141
<PAGE> 20
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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, world and
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
factors and the availability and price of transportation to consuming areas.
Energen Resources enters into derivative commodity instruments to hedge its
exposure to the impact of price fluctuations on oil and gas production. Such
instruments include regulated natural gas and crude oil futures contracts traded
on the New York Mercantile Exchange 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. These transactions are
accounted for under the hedge method of accounting. Under this method, any
unrealized gains and losses are recorded as a current receivable/payable with a
corresponding deferred gain/loss. Realized gains and losses are deferred as
current 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
deferred losses of $75.1 million and $16.5 million included in prepayments and
other on the balance sheet as of June 30, 2000, and September 30, 1999,
respectively.
<PAGE> 21
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits
27.1 Financial data schedule of Energen Corporation (for SEC purposes
only)
27.2 Financial data schedule of Alabama Gas Corporation (for SEC purposes
only)
b. Reports on Form 8-K
No reports on Form 8-K were filed for the three months ended June 30, 2000.
<PAGE> 22
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
August 11, 2000 By /s/ Wm. Michael Warren, Jr.
Wm. Michael Warren, Jr.
Chairman, President and Chief Executive
Officer of Energen, Chairman and Chief
Executive Officer of Alabama Gas
Corporation
August 11, 2000 By /s/ G. C. Ketcham
G. C. Ketcham
Executive Vice President, Chief
Financial Officer and Treasurer of
Energen and Alabama Gas Corporation
August 11, 2000 By /s/ Grace B. Carr
Grace B. Carr
Controller of Energen
August 11, 2000 By /s/ Paula H. Rushing
Paula H. Rushing
Vice President-Finance of Alabama Gas
Corporation
