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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTER ENDED MARCH 31, 1999 COMMISSION FILE NO. 0-25214
KELLEY OIL & GAS CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 76-0447267
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
601 JEFFERSON
SUITE 1100
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
Registrant's telephone number, including area code: (713) 652-5200
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
<TABLE>
<CAPTION>
TITLE OF CLASS OUTSTANDING AT APRIL 30, 1999
<S> <C>
Common Stock 126,022,235
</TABLE>
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KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
INDEX
<TABLE>
<CAPTION>
PART I. FINANCIAL INFORMATION PAGE
----
<S> <C>
See Part II. , Item 5. Other Information.
PART II. OTHER INFORMATION................................................................................. 2
Item 3. Arrearages in Payments of Dividends............................................................. 2
Item 5. Other Information............................................................................... 3
Section A. Index to Financial Statements.............................................................. 3
Section B. Management's Discussion and Analysis of Financial Condition and Results of Operations...... 36
Section C. Quantitative and Qualitative Disclosure About Market Risk.................................. 43
</TABLE>
1
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PART II. OTHER INFORMATION
ITEM 3. ARREARAGES IN PAYMENT OF DIVIDENDS
As of May 17, 1999, total dividends in arrears on the Company's $2.625
Convertible Exchangeable Preferred Stock ("Preferred Stock") were $6.8 million.
2
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ITEM 5. OTHER INFORMATION
DISPOSITION OF ASSETS.
In April 1999, the Company entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
the Company's interests in the Bryceland, West Bryceland and Sailes fields in
north Louisiana. Pursuant to the agreement, the Company (1) received an $83
million cash payment (subject to certain post-closing adjustments), (2)
retained a 42 Bcf, 8-year volumetric overriding royalty interest and a 1%
override on the excess of production above such royalty interest and (3)
retained 25% of its working interest in the Cotton Valley formation. In
addition, Phillips, will at its risk and expense, operate, develop, exploit and
explore the properties thereby relieving the Company of significant operating,
exploration and development costs in the future. The effective date of the
transaction was May 1, 1999 and it closed on May 17, 1999.
SECTION A. INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES: PAGE
----
<S> <C>
Independent Auditors' Report.............................................................................. 4
Consolidated Balance Sheets - December 31, 1997, 1998 and March 31, 1999.................................. 5
Consolidated Statements of Income (Loss) - For the years ended December 31, 1996,
1997 and 1998, the three months ended March 31, 1998 (unaudited) and 1999............................... 6
Consolidated Statements of Cash Flows - For the years ended December 31, 1996,
1997 and 1998, the three months ended March 31, 1998 (unaudited) and
1999................................................................................................... 7
Consolidated Statements of Changes in Stockholders' Deficit - For the years ended
December 31, 1996, 1997 and 1998, and for the three months ended March 31, 1999......................... 8
Notes to Consolidated Financial Statements................................................................ 9
</TABLE>
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INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of Kelley Oil & Gas Corporation:
We have audited the accompanying consolidated balance sheets of Kelley
Oil & Gas Corporation and subsidiaries (the "Company") as of December 31, 1997
and 1998 and March 31, 1999, and the related consolidated statements of income
(loss), cash flows, and changes in stockholders' deficit for each of the three
years in the period ended December 31, 1998 and the three months ended March 31,
1999. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of Kelley Oil & Gas Corporation
and subsidiaries as of December 31, 1997 and 1998 and March 31, 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1998 and the three months ended March 31, 1999, in
conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Houston, Texas
May 17, 1999
4
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KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------ MARCH 31,
1997 1998 1999
---------- ---------- ----------
<S> <C> <C> <C>
ASSETS:
Cash and cash equivalents .................................................. $ 162 $ 8,435 $ 6,710
Accounts receivable ........................................................ 24,566 18,071 17,926
Accounts receivable - drilling programs .................................... 718 624 573
Prepaid expenses and other current assets .................................. 1,412 1,121 768
---------- ---------- ----------
Total current assets ..................................................... 26,858 28,251 25,977
---------- ---------- ----------
Oil and gas properties, successful efforts method:
Unproved properties, net ................................................. 49,854 38,293 38,455
Properties subject to amortization ....................................... 463,263 496,686 500,980
Pipelines and other transportation assets, at cost ......................... 4,690 1,582 1,582
Furniture, fixtures and equipment .......................................... 2,969 3,554 3,567
---------- ---------- ----------
520,776 540,115 544,584
Less: Accumulated depreciation, depletion and amortization ................ (227,163) (283,660) (293,620)
---------- ---------- ----------
Total property and equipment, net ........................................ 293,613 256,455 250,964
Other non-current assets, net .............................................. 2,131 1,491 1,298
---------- ---------- ----------
Total assets ............................................................. $ 322,602 $ 286,197 $ 278,239
========== ========== ==========
LIABILITIES:
Accounts payable and accrued expenses ...................................... $ 41,474 $ 33,113 $ 35,078
Accounts payable - drilling programs ....................................... 566 272 276
Current portion of long-term debt .......................................... -- 32,251 32,851
---------- ---------- ----------
Total current liabilities ................................................ 42,040 65,636 68,205
---------- ---------- ----------
Long-term debt ............................................................. 286,183 287,500 287,959
---------- ---------- ----------
Total liabilities ........................................................ 328,223 353,136 356,164
---------- ---------- ----------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' DEFICIT:
Preferred stock, $1.50 par value, 20,000,000 shares authorized at December
31, 1997, 1998 and March 31, 1999; 1,745,443, 1,733,628 and 1,733,628
shares issued and outstanding at December 31, 1997, 1998 and March 31,
1999, respectively
(liquidation value $48,977, $48,633 and $49,771, respectively) ........... 2,618 2,600 2,600
Common stock, $.01 par value, 200,000,000 shares authorized
at December 31, 1997, 1998 and March 31, 1999; 125,709,093,
126,022,235 and 126,022,235 shares issued and outstanding at
December 31, 1997, 1998 and March 31, 1999, respectively ................. 1,257 1,260 1,260
Additional paid-in capital ................................................. 300,367 300,653 300,653
Accumulated deficit ........................................................ (309,863) (371,452) (382,438)
---------- ---------- ----------
Total stockholders' deficit .............................................. (5,621) (66,939) (77,925)
---------- ---------- ----------
Total liabilities and stockholders' deficit .............................. $ 322,602 $ 286,197 $ 278,239
========== ========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
5
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KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED MARCH 31,
-------------------------------------- ------------------------
1996 1997 1998 1998 1999
---------- ---------- ---------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
REVENUES:
Oil and gas revenues ....................... $ 60,854 $ 75,864 $ 79,150 $ 23,047 $ 15,507
Interest and other income .................. 1,429 274 505 24 161
---------- ---------- ---------- ---------- ----------
Total revenues ............................. 62,283 76,138 79,655 23,071 15,668
---------- ---------- ---------- ---------- ----------
COSTS AND EXPENSES:
Production expenses ........................ 10,709 10,955 19,878 4,898 5,284
Exploration expenses ....................... 5,438 5,433 12,034 2,051 1,370
General and administrative expenses ........ 8,953 6,875 7,077 1,909 1,374
Interest and other debt expenses ........... 24,401 25,071 33,333 8,092 8,666
Restructuring expenses ..................... 4,276 - - - -
Depreciation, depletion and amortization ... 20,440 25,853 38,602 10,944 9,960
Impairment of oil and gas properties ....... - - 25,738 - -
---------- ---------- ---------- ---------- ----------
Total expenses ............................. 74,217 74,187 136,662 27,894 26,654
---------- ---------- ---------- ---------- ----------
Income (loss) before income taxes and
extraordinary item ......................... (11,934) 1,951 (57,007) (4,823) (10,986)
Income taxes ............................... - - - - -
---------- ---------- ---------- ---------- ----------
Net income (loss) before extraordinary item ... (11,934) 1,951 (57,007) (4,823) (10,986)
Extraordinary item ......................... (17,030) - - - -
---------- ---------- ---------- ---------- ----------
Net income (loss) ............................. (28,964) 1,951 (57,007) (4,823) (10,986)
Less: cumulative preferred stock dividends . (4,582) (4,582) (4,550) (1,145) (1,137)
---------- ---------- ---------- ---------- ----------
Net loss applicable to common stock ........... $ (33,546) $ (2,631) $ (61,557) $ (5,968) $ (12,123)
========== ========== ========== ========== ==========
Basic and diluted loss per common share
before extraordinary item .................. $ (.18) $ (.03) $ (0.49) $ (0.05) $ (0.10)
========== ========== ========== ========== ==========
Basic and diluted loss per common share ....... $ (.37) $ (.03) $ (0.49) $ (0.05) $ (0.10)
========== ========== ========== ========== ==========
Weighted average common shares outstanding .... 90,113 100,757 125,783 125,710 126,022
========== ========== ========== ========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
6
<PAGE> 8
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED MARCH 31,
-------------------------------------- ------------------------
1996 1997 1998 1998 1999
---------- ---------- ---------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) ................................. $ (28,964) $ 1,951 $ (57,007) $ (4,823) $ (10,986)
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Depreciation, depletion
and amortization .............................. 20,440 25,853 38,602 10,944 9,960
Impairment of oil and gas properties ............ -- -- 25,738 -- --
Gain on sale of properties ...................... (176) -- -- -- --
Exploration expenses ............................ 5,438 5,433 12,034 2,051 1,370
Accretion and amortization of other
debt expenses ................................. 5,170 4,297 5,236 1,394 1,233
Restructuring expenses .......................... 4,276 -- -- -- --
Extraordinary loss .............................. 17,030 -- -- -- --
Changes in operating assets and liabilities:
Decrease (increase) in accounts
receivable and other current assets ........... (9,054) (1,297) 6,880 676 549
(Increase) decrease in other non-current assets . (1,945) (1,203) (526) 33 3
Increase (decrease) in accounts
payable and accrued expenses .................. (2,953) 4,570 (8,655) (589) 1,969
---------- ---------- ---------- ---------- ----------
Net cash provided by operating activities ......... 9,262 39,604 22,302 9,686 4,098
---------- ---------- ---------- ---------- ----------
INVESTING ACTIVITIES:
Capital expenditures .............................. (47,601) (53,140) (56,579) (12,881) (5,823)
Acquisition of oil and gas properties ............. (11,594) (111,135) -- -- --
Proceeds from sale of properties .................. 5,803 -- 17,363 -- --
---------- ---------- ---------- ---------- ----------
Net cash used in investing activities ............. (53,392) (164,275) (39,216) (12,881) (5,823)
---------- ---------- ---------- ---------- ----------
FINANCING ACTIVITIES:
Proceeds from long-term borrowings ................ 50,000 180,500 119,100 34,100 --
Principal payments on long-term borrowings ........ (58,500) (82,700) (118,900) (30,800) --
Proceeds from sale of notes, net .................. 120,938 -- 29,526 -- --
Debenture conversion costs ........................ (1,100) -- -- -- --
Proceeds from sale of common stock, net ........... 43,998 27,545 273 1 --
Proceeds from conversion of preferred stock ....... -- -- (2) -- --
Retirement of notes ............................... (113,488) -- (228) (228) --
Dividends on preferred stock ...................... -- (4,582) (4,582) -- --
---------- ---------- ---------- ---------- ----------
Net cash provided by financing activities ......... 41,848 120,763 25,187 3,073 --
---------- ---------- ---------- ---------- ----------
(Decrease) increase in cash and cash equivalents ..... (2,282) (3,908) 8,273 (122)
(1,725)
Cash and cash equivalents, beginning of period ....... 6,352 4,070 162 162 8,435
---------- ---------- ---------- ---------- ----------
Cash and cash equivalents, end of period ............. $ 4,070 $ 162 $ 8,435 $ 40 $ 6,710
========== ========== ========== ========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
7
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KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' DEFICIT
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
ADDITIONAL
PREFERRED COMMON PAID IN ACCUMULATED
STOCK STOCK CAPITAL DEFICIT
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Stockholders' deficit at January 1, 1996 ................. $ 6,456 $ 440 $ 225,804 $ (278,268)
Issuance of 48,000 shares of common stock in
Contour Transaction ................................... -- 480 47,520 --
Conversion of 697 shares of preferred stock into
4,355 shares of common stock .......................... (1,045) 44 1,001 --
Conversion of 1,862 shares of preferred stock into
1,862 shares of common stock .......................... (2,793) 19 2,774 --
Issuance of 36 shares of common stock pursuant to
employee incentive stock options ...................... -- -- 62 --
Syndication costs ........................................ -- -- (4,065) --
Net loss ................................................. -- -- -- (28,964)
------------- ------------- ------------- -------------
BALANCE AT DECEMBER 31, 1996 .......................... 2,618 983 273,096 (307,232)
------------- ------------- ------------- -------------
Issuance of 27,000 shares of common stock in
Contour Transaction ................................... -- 270 26,730 --
Issuance of 415 shares of common stock pursuant to
employee incentive stock options ...................... -- 4 541 --
Preferred stock dividends ................................ -- -- -- (4,582)
Net income ............................................... -- -- -- 1,951
------------- ------------- ------------- -------------
BALANCE AT DECEMBER 31, 1997 .......................... 2,618 1,257 300,367 (309,863)
------------- ------------- ------------- -------------
Conversion of 11,815 shares of preferred stock
into 40,976 share of common stock ..................... (18) 1 17 --
Issuance of 272,166 shares of common stock pursuant to
employee incentive stock options ...................... -- 2 269 --
Preferred stock dividends ................................ -- -- -- (4,582)
Net loss ................................................. -- -- -- (57,007)
------------- ------------- ------------- -------------
BALANCE AT DECEMBER 31, 1998 .......................... 2,600 1,260 300,653 (371,452)
------------- ------------- ------------- -------------
Net loss ................................................. -- -- -- (10,986)
------------- ------------- ------------- -------------
BALANCE AT MARCH 31, 1999 ............................. $ 2,600 $ 1,260 $ 300,653 $ (382,438)
============= ============= ============= =============
</TABLE>
See Notes to Consolidated Financial Statements.
8
<PAGE> 10
KELLEY OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - INDUSTRY CONDITIONS AND LIQUIDITY
During 1998 and through the first quarter of 1999, the oil and gas
industry experienced a worldwide excess of supply over demand for oil and
natural gas resulting in sharply reduced prices. As a result, many companies in
the oil and gas industry, including Kelley Oil & Gas Corporation ("the
Company"), experienced reduced profitability and cash flows which, in turn,
created significant liquidity problems. To address these liquidity issues, the
Company has taken the measures discussed in the following paragraphs.
In April 1999, the Company entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
the Company's interests in the Bryceland, West Bryceland and Sailes fields in
north Louisiana. Pursuant to the agreement, the Company (1) received an $83
million cash payment (subject to certain post-closing adjustments), (2) retained
a 42 Bcf, 8-year volumetric overriding royalty interest and a 1% override on the
excess of production above such royalty interest and (3) retained 25% of its
working interest in the Cotton Valley formation. In addition, Phillips, will at
its risk and expense, operate, develop, exploit and explore the properties
thereby relieving the Company of significant operating, exploration and
development costs in the future. The effective date of the transaction was May
1, 1999 and it closed on May 17, 1999. The Company anticipates recognition of a
gain ranging from approximately $24 million to $28 million in the second quarter
of 1999. The Company has not completed its analysis of the specific costs of the
oil and gas properties and related accumulated depreciation, depletion and
amortization being sold, and accordingly, the gain is subject to further
adjustment.
In April 1999, the Company negotiated a private offering of $135
million principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are
secured by a first lien on substantially all of the Company's proved oil and
natural gas properties remaining after the sale to Phillips and guaranteed by
three entities wholly-owned by the Company. With the consummation of the
Phillips transaction, the Company is obligated to offer to repurchase $35
million principal amount of the Notes at a repurchase price equal to 104% of the
principal amount, plus accrued and unpaid interest to the date of the repurchase
within 30 days of such closing.
In April 1999, the Company began an offer to purchase ("Offer to
Purchase") the outstanding principal amounts of its 7 7/8% Convertible
Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated
Debentures due April 1, 2000 (collectively, the "Securities") at a price equal
to $590 per $1,000 principal amount. On May 17, 1999, the Company funded the
repurchase of $46.1 million of the Securities through the Offer to Purchase and
will recognize an extraordinary gain of approximately $18.9 million in the
second quarter of 1999.
The net proceeds from the combination of these transactions and cash
on hand were used by the Company to repay all borrowings outstanding under its
Credit Facility of $115.5 million plus accrued interest, to fund cash
collateral for a $1.5 million letter of credit, and to fund the repurchase of
$46.1 million of Securities under the Offer to Purchase, all at May 17, 1999.
The remaining net proceeds and cash flow from operations will be used to
repurchase up to $35 million of Notes at 104% of their principal amount and
for general corporate purposes.
While industry conditions cannot be predicted with certainty and are
dependent upon a number of commodity and economic factors which are beyond the
company's control, the Company believes that the cash on hand subsequent to the
consummation of the above transactions and the recent increase in oil and
natural gas prices, if continued, will sustain its operations over the
short-term. However, the Company will continue to have significant debt
outstanding and limited ability to incur further indebtedness, which, combined
with industry conditions beyond its control, may adversely affect its financial
condition, results of operations and cash flows.
9
<PAGE> 11
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Operations. Kelley Oil & Gas Corporation (a Delaware
Corporation), its corporate subsidiaries and proportionate partnership interests
are referred to herein as the "Company". The Company is an independent oil & gas
company engaged in the exploration, development and acquisition of domestic oil
and gas properties, principally in the Gulf Coast region and northern Louisiana.
Cash and Cash Equivalents. The Company considers all highly liquid
investments with an original maturity of three months or less when purchased to
be cash equivalents. Cash payments attributable to interest on all indebtedness
aggregated $19.2 million, $19.6 million and $26.5 million for the years ended
December 31, 1996, 1997 and 1998, respectively, and $2.3 million and $2.0
million for the periods ended March 31, 1998 (unaudited) and March 31, 1999,
respectively.
Financial Instruments. The Company's financial instruments consist of
cash and cash equivalents, receivables, payables and long term debt. As of
December 31, 1998 and March 31, 1999, the estimated fair value of the Company's
long-term debt was $251 million and $246 million, respectively. The fair value
of such long-term debt has been estimated based on quoted market prices. The
carrying amount of the Company's other financial instruments approximates fair
value.
Oil and Gas Properties. All of the Company's interests in its oil and
gas properties are located in the United States and are accounted for using the
successful efforts method. Under the successful efforts method, the costs of
successful wells, development dry holes and leases containing productive
reserves are capitalized and amortized on a unit-of-production basis over the
life of the related reserves. Estimated future abandonment and site restoration
costs, net of anticipated salvage values, are amortized on a unit-of-production
basis over the life of the related reserves. Exploratory drilling costs are
initially capitalized pending determination of proved reserves but are charged
to expense if no proved reserves are found. Other exploration costs, including
geological and geophysical expenses, leasehold expiration costs and delay
rentals, are expensed as incurred. Unproved leasehold costs are capitalized and
are not amortized pending an evaluation of the exploration results. Unproved
properties are periodically assessed for impairment in value, with any
impairment charged to expense.
Property Impairment under SFAS 121. Under Financial Accounting
Standards Board's Statement No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"),
certain assets are required to be reviewed periodically for impairment whenever
circumstances indicate their carrying amount exceeds their fair value and may
not be recoverable. As a result of a decline in its proved reserves at January
1, 1999 from year-earlier levels, the Company performed an assessment of the
fair value of its oil and gas properties indicating an impairment should be
recognized as of year end. Under this analysis, the fair value for the Company's
proved oil and gas properties was estimated using escalated pricing and present
value discount factors reflecting risk assessments. The fair value of the
Company's unproved properties was predicated on current acreage cost estimates.
Based on this analysis, the Company recognized noncash impairment charges
against the carrying values of its proved and unproved oil and gas properties
under SFAS 121 aggregating $21.6 million and $4.1 million, respectively, at
December 31, 1998. Prices of oil and natural gas have increased since December
31, 1998 so that no additional impairment was required at March 31, 1999.
Other Property and Equipment. The costs of pipelines and other
transportation assets are depreciated using the straight-line method over the
estimated useful lives of the related assets. Furniture, fixtures and equipment
are recorded at cost and depreciated using the straight-line method over the
estimated useful lives of three to five years. Maintenance and repairs are
charged to expense as incurred.
Other Non-Current Assets. Other non-current assets consist primarily of
debt issue costs, net of accumulated amortization. These costs are amortized
over the anticipated term of the related debt.
Oil and Gas Revenues. The Company recognizes oil and gas revenue from
its interests in producing wells as oil and gas is produced and sold from those
wells. Oil and gas sold is not significantly different from the Company's
production entitlement. Revenues from gas marketing, net of cost of gas sold,
are included in oil and gas revenues and amounted to $1.8 million, $2.8 million
and $1.3 million for the years ended December 31, 1996,
10
<PAGE> 12
1997 and 1998, respectively, and $0.5 million and $0.6 million, for the periods
ended March 31, 1998 (unaudited) and March 31, 1999, respectively.
Earnings per Share. In 1997, the Company implemented the Financial
Accounting Standards Board Statement of Financial Accounting Standards No. 128,
"Earnings Per Share" ("SFAS 128"). SFAS 128 establishes standards for computing
and presenting earnings per share ("EPS") and is effective for financial
statements issued for periods ending after December 15, 1997. This statement
requires restatement for all prior-period EPS data presented. The basic loss per
common share before extraordinary item and basic loss per common share as shown
on the Consolidated Statements of Income (Loss) reflects net income (loss)
before extraordinary item and net income (loss), respectively, less cumulative
preferred stock dividends, whether or not declared, divided by the weighted
average number of common shares outstanding during the respective years. The
extraordinary loss per common share for the year ended 1996 was $0.19. In
calculating diluted income (loss) per share, common shares issuable under stock
options and upon conversion of convertible subordinated debentures and
convertible preferred stock are added to the weighted average common shares
outstanding when dilutive. For the years ended December 31, 1996, 1997 and 1998,
and for the periods ended March 31, 1998 (unaudited) and 1999, all potentially
dilutive securities are anti-dilutive and therefore are not included in the EPS
calculations. As of March 31, 1999, potentially dilutive securities which could
impact EPS in the future include stock options granted to employees to purchase
4.0 million common shares, the Company's 7 7/8% Convertible Subordinated Notes
and 8 1/2% Convertible Subordinated Debentures which can be converted into 2.5
million and 1.4 million common shares, respectively, and the Company's $2.625
Convertible Preferred Stock which can be converted into 6.0 million shares. See
Note 1 regarding the Company's purchase of a portion of the outstanding 7 7/8%
Convertible Subordinated Notes and 8 1/2% Convertible Subordinated Debentures.
Stock Based Compensation. The Company applies Accounting Principles
Board Opinion No. 25 ("APB 25") and related Interpretations in accounting for
stock option and purchase plans. Under APB 25, compensation expense, if any, is
based on the intrinsic value of the equity instrument at the measurement date.
The Company has not recognized any compensation expense because the exercise
price of employee stock options equals the market price of the underlying stock
on the date of the grant.
Derivatives and Hedging Activities. See Note 10 for a discussion of
the Company's accounting policies related to hedging activities. In June 1998,
the Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting
standards for derivative instruments and hedging activities that require an
entity to recognize all derivatives as an asset or liability measured at its
fair value. Depending on the intended use of the derivatives, changes in its
fair value will be reported in the period of change as either a component of
earnings or a component of other comprehensive income.
SFAS 133 is effective for all fiscal quarters of fiscal years beginning
after June 15, 1999. Earlier application of SFAS 133 is encouraged, but not
prior to the beginning of any fiscal quarter that begins after issuance of the
Statement. Retroactive application to periods prior to adoption is not allowed.
Comprehensive Income. In June 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting
and displaying comprehensive income and its components. SFAS 130 is effective
for periods beginning after December 15, 1997. The purpose of reporting
comprehensive income is to report a measure of all changes in equity of an
enterprise that results from recognized transactions and other economic events
of the period other than transactions with owners in their capacity as owners.
For all applicable periods through March 31, 1999, there are no adjustments
("Other Comprehensive Income") to net income in deriving comprehensive income.
Risks and Uncertainties. 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 and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
11
<PAGE> 13
Interim Presentation. The accompanying consolidated interim financial
statements and disclosures for 1998 (unaudited) and 1999, have been prepared by
the Company in accordance with generally accepted accounting principles and, in
the opinion of management, reflect all adjustments (consisting solely of normal
recurring adjustments) necessary for a fair presentation in all material
respects of the results for the interim periods. The interim financial
statements for the three months ended March 31, 1998 (unaudited) and 1999 should
be read in conjunction with the Company's annual consolidated financial
statements contained in its Annual Report on Form 10-K for the year ended
December 31, 1998. The results of operations for the three months ended March
31, 1999 are not necessarily indicative of results to be expected for the full
year.
Changes in Presentation. Certain financial statement items in 1996,
1997 and 1998 have been reclassified to conform to the 1999 presentation.
NOTE 3 - ACQUISITION OF OIL AND GAS PROPERTIES
SPR Acquisition. On December 1, 1997, the Company purchased from SCANA
Petroleum Resources, Inc. ("SPR") substantially all of SPR's assets, including
its oil and gas properties, exploratory leasehold interests and associated
obligations, in exchange for approximately $110 million ("SPR Acquisition"),
subject to adjustment as provided by the Purchase and Sale Agreement between the
Company and SPR. The acquisition was accounted for using the purchase method of
accounting, and accordingly, the purchase price has been allocated to the assets
acquired based on estimated fair values at the date of acquisition. The
operating results of the assets acquired from SPR have been included in Kelley's
Consolidated Statements of Income (Loss) since December 1, 1997. The pro forma
information shown below assumes that the acquisition occurred at the beginning
of each year presented. Adjustments have been made to reflect changes in the
Company's results from the revenues and direct operating expenses of the
producing properties acquired from SPR, additional interest expense to finance
the acquisition, depreciation, depletion and amortization based on assigned fair
values to the assets acquired and general and administrative expenses incurred
from hiring additional employees. The unaudited pro forma financial data are not
necessarily indicative of financial results that would have occurred had the SPR
Acquisition occurred on January 1, 1996 and January 1, 1997, and should not be
viewed as indicative of operations in future periods.
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
(UNAUDITED)
-----------------------------
YEAR ENDED DECEMBER 31,
-----------------------------
1996 1997
----------- -----------
<S> <C> <C>
Revenues............................................................... $ 112,936 $ 112,142
Income (loss) before extraordinary item................................ (12,484) 1,315
Net income (loss)...................................................... (29,514) 1,315
Loss per common share.................................................. (0.29) (0.03)
</TABLE>
12
<PAGE> 14
NOTE 4 - LONG-TERM DEBT
Long-Term Debt. The Company's long-term debt at December 31, 1997 and
1998 and March 31, 1999 is comprised of the following:
(IN THOUSANDS)
<TABLE>
<CAPTION>
December 31, March 31,
----------------------- ----------
1997 1998 1999
---------- ---------- ----------
<S> <C> <C> <C>
Bank credit facilities ....................................... $ 111,300 $ 111,500 $ 111,500
13 1/2% Senior Notes ......................................... 435 435 435
10 3/8% Senior Subordinated Notes ............................ 120,615 150,662 150,818
7 7/8% Convertible Subordinated Notes ........................ 29,710 31,816 32,416
8 1/2% Convertible Subordinated Debentures ................... 24,123 25,338 25,641
---------- ---------- ----------
286,183 319,751 320,810
Less current maturities ................................... -- (32,251) (32,851)
---------- ---------- ----------
$ 286,183 $ 287,500 $ 287,959
========== ========== ==========
</TABLE>
Bank Credit Facilities. The Company replaced its prior credit facility
with a new credit facility effective as of December 12, 1996 (the "Credit
Facility") that was subsequently amended and restated in connection with the SPR
Acquisition effective December 1, 1997. The borrowers under the Credit Facility
are the Company, Kelley Oil Corporation ("Kelley Oil") and Kelley Operating
Company, Ltd., with Concorde Gas Marketing, Inc. (a wholly-owned subsidiary of
the Company) and the Company's subsidiary partnerships as guarantors.
The Credit Facility provides for a maximum $140 million revolving
credit loan and matures, with all amounts owed thereunder becoming due and
payable on December 1, 2000. Availability under the Credit Facility is limited
to a borrowing base determined by, among other things, the proved oil and
natural gas reserves and other assets of the borrowers and the value of those
reserves based on the underlying prices for oil and natural gas. The Borrowing
Base is redetermined at least semiannually by the Agent under the Credit
Facility, with the consent of 100% of the lenders, and may be redetermined more
frequently at the election of the lenders or the borrowers. On April 14, 1998,
the Borrowing Base was set at $138 million and the threshold amount (the
"Threshold Amount"), which is the amount that would ordinarily be made available
by the lenders to a similar borrower under a borrowing base, was set at $125
million. Following the Company's sale of its interest in the Waskom field in
July 1998, the Borrowing Base and Threshold Amount were reduced to $130 million
and $117 million, respectively. As provided in the Credit Facility, on November
1, 1998 the Borrowing Base was reduced to equal the Threshold Amount of $117
million.
On December 29, 1998 the Borrowing Base under the Credit Facility was
maintained at $117 million and certain terms were amended, including: (i) an
increase in the margin borrowing rate to 250 basis points over LIBOR, (ii) a
reduction in the grace periods available under certain default provisions, (iii)
a change in the definition of majority banks for purposes of setting the
semi-annual Borrowing Base and implementing other provisions from 75% to 100%,
and (iv) a reduction in the time allowed to cure a Borrowing Base deficiency to
30 days.
At December 31, 1998 and March 31, 1999, $111.5 million of borrowings
and $1.5 million of letters of credit were outstanding under the Credit
Facility. In April 1999 the Company borrowed an additional $4 million under the
Credit Facility, raising its total outstanding borrowings to $115.5 million as
of April 30, 1999. The Company's typical monthly cash flow cycle is such that
the Company usually receives a substantial portion of its proceeds from
operations near the end of each month. Accordingly, outstanding balances under
the Credit Facility may be higher on any given day during the month than at the
end of the month. The weighted average interest rates on borrowings outstanding
at December 31, 1998 and March 31, 1999 under the Credit Facility were 7.03% and
6.78%, respectively.
13
<PAGE> 15
As of March 31, 1999, the Company was in default on certain covenants
under the Credit Facility. In addition, a review of the Borrowing Base was
scheduled for May 1, 1999, at which time the Company expected the current $117
million Borrowing Base to be lowered. The excess of the amounts outstanding over
the new Borrowing Base would have been due and payable within 30 days. The
Company received waivers of these defaults through May 17, 1999, at which time
all amounts due under the Credit Facility were repaid and the Credit Facility
was terminated (see Note 1). Following the sale of the Notes, the Company's
ability to negotiate a new revolving credit facility will be severely limited.
1996 Fourth Quarter Extraordinary Loss. Pursuant to an offer to
purchase and consent solicitation, dated September 24, 1996, as amended , the
Company offered to purchase for cash up to the aggregate principal amount of
$100 million of its 13 1/2% Senior Notes at a cash price equal to $1,110 per
$1,000 principal amount, plus interest accrued and unpaid through the payment
date. In conjunction with the offering, the Company also solicited consents to
the adoption of certain amendments to the 13 1/2% Senior Notes indenture
pursuant to which the 13 1/2% Senior Notes were issued, and offered to pay each
consenting holder of the 13 1/2% Senior Notes, $30 for each $1,000 principal
amount of the 13 1/2% Senior Notes consenting. The Company received the
requisite consents which allowed it to amend the 13 1/2% Senior Notes indenture
on October 28, 1996. The Company also received tenders from holders of
approximately $99.6 million principal amount of the 13 1/2% Senior Notes. These
transactions resulted in an extraordinary loss in the fourth quarter of 1996 of
$17.0 million, representing the excess of the aggregate purchase price of the 13
1/2% Notes (including Consent Payments) over their carrying value as of the date
of the consummation of the refinancing.
10 3/8% Senior Subordinated Notes. In connection with the refinancing
of the 13 1/2% Senior Notes, the Company issued an aggregate principal amount of
$125.0 million of 10 3/8% Senior Subordinated Notes due 2006 (the "10 3/8%
Senior Subordinated Notes"). The 10 3/8% Senior Subordinated Notes are
redeemable at the option of the Company, in whole or in part, at redemption
prices declining from 105.19% in 2001 to 100% in 2003 and thereafter. The
Company may redeem up to 35% of the principal amount of the 10 3/8% Senior
Subordinated Notes before October 15, 1999 with the proceeds of an equity
offering (provided that either at least $75.0 million aggregate principal amount
of such notes remains outstanding or such redemption retires such notes in their
entirety). The 10 3/8% Senior Subordinated Notes represent unsecured obligations
of the Company and are subordinate in right of payment to all existing and
future senior indebtedness. The indenture for the notes contains conditions and
limitations, including but not limited to restrictions on additional
indebtedness, payment of dividends, redemption of capital stock, and certain
mergers and consolidations. The holder of the 10 3/8% Senior Subordinated Notes
also can require the Company to repurchase the notes at 101% of the principal
amount upon a Change of Control, as defined. Kelley Oil Corporation, a
wholly-owned subsidiary of the Company and Kelley Operating Company, Ltd., an
indirect wholly-owned partnership of the Company are guarantors of the 10 3/8%
Senior Subordinated Notes.
On February 3, 1997, the Company completed an exchange of $125.0
million aggregate principal amount of publicly registered 10 3/8% Senior
Subordinated Notes, Series B, for all of the then outstanding Series A notes.
The Series B notes were substantially identical to the Series A notes.
In May 1998, the Company sold $30.0 million principal amount of the
Company's 10 3/8% Senior Subordinated Notes due 2006, Series C ("Series C
Notes") at a cash price of $1,015 per $1,000 principal amount. The net proceeds
received were used to reduce outstanding borrowings under the Company's bank
credit facility ("Credit Facility"). The Series C Notes are redeemable at the
option of the Company, in whole or in part, at redemption prices declining
ratably from 105.19% on October 15, 2001 to 100% at October 15, 2003 and
thereafter. The Company may redeem up to 35% of the original principal amount of
the Series C Notes before October 15, 1999 at 110.38% with the proceeds of an
equity offering (provided that either at least $18.0 million aggregate principal
amount of such notes remains outstanding or such redemption retires such notes
in their entirety). The Series C Notes represent unsecured obligations of the
Company and are subordinate in right of payment to all existing and future
senior indebtedness. The indenture for the notes contains conditions and
limitations, including but not limited to restrictions on additional
indebtedness, payment of dividends, redemption of capital stock, and certain
mergers and consolidations. The holders of the Series C Notes also can require
the Company to repurchase the notes at 101% of the principal amount upon a
Change of Control, as defined. Kelley Oil Corporation, a wholly owned subsidiary
of the Company, and Kelley Operating Company, Ltd., an indirect wholly owned
partnership of the Company, are guarantors of the Series C Notes.
14
<PAGE> 16
The Series C Notes were sold pursuant to Rule 144A of the Securities
Act of 1933. In issuing the Series C Notes, the Company agreed to use its best
efforts to register under the Securities Act notes identical in terms to the
Series C Notes ("Series D Notes"). The Company completed the exchange of the
Series C Notes for the Series D Notes on November 12, 1998.
7 7/8% Convertible Subordinated Notes and 8 1/2% Convertible
Subordinated Debentures. The Company has outstanding 7 7/8% Convertible
Subordinated Notes due December 1999 (the "7 7/8% Subordinated Notes") in the
aggregate principal amount at maturity of $34.1 million and 8 1/2% Convertible
Subordinated Debentures due April 1, 2000 (the "8 1/2% Subordinated Debentures")
in the aggregate principal amount of $26.9 million (together, the "Subordinated
Debt"). Each $1,000 face value amount of the 7 7/8% Subordinated Notes is
convertible into 71.263 shares of the Company's Common Stock or 35.632 shares of
the Company's Common Stock and 7.435 shares of Preferred Stock. Each $1,000 face
value amount of the 8 1/2% Subordinated Debentures is convertible into 51.864
shares of the Company's Common Stock or 25.932 shares of the Company's Common
Stock and 5.411 shares of Preferred Stock.
Under the Indenture for the 7 7/8% Subordinated Notes, as amended, a
"Change in Control" is defined to occur if, among other things, any person
becomes the beneficial owner of securities representing 50% or more of the
equity interests in the Company. With the purchase by Contour of 27 million
shares on December 1, 1997, each holder of 7 7/8% Subordinated Notes, was
afforded the right, at the holder's option, subject to terms and conditions of
the Indenture, to require the Company to redeem all or any part of the holder's
notes by January 22, 1998 at a specified cash price. Holders redeemed $0.2
million of the 7 7/8% Subordinated Notes under the Change of Control provision.
See Note 1 regarding the Company's purchase of a portion of the
outstanding 7 7/8% Convertible Subordinated Notes and 8 1/2% Convertible
Subordinated Debentures.
14% Senior Secured Notes Due 2003. On April 16, 1999, the Company
issued $135,000,000 of Senior Secured Notes due 2003, maturing at 105% of the
stated principal amount. Interest will accrue from the issue date and will be
payable semi-annually in cash in arrears on each April 15 and October 15,
commencing October 15, 1999. As a result of the consummation of the Phillips
transaction, by June 16, 1999, the Company must offer to redeem $35 million of
the Notes at 104% of par. The remaining Notes are redeemable by the Company on
or after April 15, 2001. Scheduled mandatory redemptions of $2,000,000 per
quarter begin July 15, 2002. In addition, the indenture contains covenants that
restrict the Company's ability to incur additional indebtedness, pay dividends,
incur capital expenditures, sell assets, merge or consolidate and redeem
subordinated indebtedness.
Debt Maturities. At December 31, 1998 and March 31, 1999, the Company
has aggregate debt maturities of $34.6 million in 1999, $138.4 million in 2000
and $155.0 million in 2006.
NOTE 5 - STOCKHOLDERS' DEFICIT
Contour Stock Purchase. In February 1996, the Company issued 48 million
shares of its Common Stock at $1.00 per share to Contour Production Company
L.L.C. ("Contour") upon the closing of a Stock Purchase Agreement between the
Company and Contour (the "Contour Transaction"). The newly issued shares
represented 49.8% of the Company's voting power. In connection with the Contour
Transaction, the Company (i) entered into an option agreement with Contour (the
"Contour Option Agreement"), (ii) obtained consents from its principal
stockholders, subject to compliance with applicable securities law, to amend its
Certificate of Incorporation to increase its authorized Common Stock from 100
million shares to 200 million shares, (iii) entered into employment agreements
with John F. Bookout, President of Contour, and three other new executives named
by him, (iv) adopted a nonqualified stock option plan for the new executives
other than Mr. Bookout, (v) amended its existing incentive stock option plans,
(vi) reduced the size of its board of directors (the "Board") to seven members
and reconstituted the Board with three continuing directors and four designees
of Contour and (vii) replaced its credit facility.
Contour Option. Under the Contour Option Agreement, the Company granted
Contour an option (the "Contour Option") to purchase up to 27 million shares
(the "Maximum Option Number") of Common Stock at $1.00
15
<PAGE> 17
per share (subject to antidilution adjustments) upon satisfaction of certain
conditions, including the absence of any Company debt repurchase or redemption
obligations as a result of the purchase. Contour voluntarily exercised its
option in full on December 1, 1997 to partially fund the SPR Acquisition.
Preferred Stock. In May 1994, Kelley Oil completed a public offering of
1,380,000 shares of $2.625 Preferred Stock ("KOIL Preferred Stock") at $25 per
share. Each outstanding share of KOIL Preferred Stock was converted in the
Consolidation into one share of the Company's Preferred Stock, which has the
same terms as the KOIL Preferred Stock, except for expanded voting rights. The
Company issued 649,807 shares of its Preferred Stock to Public Unitholders in
the Consolidation, resulting in a total of 2,442,323 outstanding shares of
Preferred Stock after giving effect to the shares issued to holders of KOIL
Preferred Stock.
In January 1996, the Company suspended the payment of the quarterly
Preferred Stock dividend scheduled for February 1, 1996 to conserve cash. On
April 15, 1997, the Board of Directors of the Company declared a dividend of
$2.625 per preferred share (approximately $4.6 million), which was paid on May
1, 1997. On April 14, 1998, the Company declared a dividend of $2.625 per share
of Preferred Stock (approximately $4.6 million), which was paid on April 30,
1998. The Company has not declared the quarterly dividends of $0.65625 per
preferred share for February 1, 1998, May 1, 1998, August 1, 1998, November 1,
1998, February 1, 1999 and May 1, 1999 aggregating approximately $6.8 million,
covering 6 quarters. Further dividends are restricted under the Company's
indentures governing its 10 3/8% Senior Subordinated Notes and its 14% Senior
Secured Notes. No interest is payable on Preferred Stock arrearages; however,
the terms of the Preferred Stock enable holders, voting separately as a class,
to elect two additional directors to the Board at each meeting of stockholders
at which directors are to be elected during any period when Preferred Stock
dividends are in arrears in an aggregate amount equal to at least six quarterly
dividends, whether or not consecutive.
Each share of Preferred Stock is convertible, at the holder's option,
into 3.47 shares of Common Stock, equivalent to a conversion price of $7.20 per
share of Common Stock relative to the $25 per share liquidation preference of
the Preferred Stock (the "Preferred Conversion Price"). Under the terms of the
Certificate of Designation governing the Preferred Stock, the Contour
Transaction triggered a special conversion right under which the Preferred Stock
conversion price was reduced to $4.00 for a period of 45 days commencing March
12, 1996. On April 25, 1996, 696,823 shares of Preferred Stock were converted
into 4,355,040 shares of Common Stock under the special conversion right.
ESOP Preferred Stock. As of December 31, 1995, 1,861,619 shares of ESOP
Preferred Stock were outstanding and held by the Company's Employee Stock
Ownership Plan ("ESOP"). In June 1996, each of the 1,861,619 shares of ESOP
Preferred Stock was redeemed for one share of the Company's Common Stock.
NOTE 6 - EMPLOYEE STOCK PLANS
Employee Stock Options. The Company has both qualified and nonqualified
stock option plans that provide for granting of options for the purchase of
common stock to key employees. These stock options may be granted for periods up
to ten years and are generally subject to vesting periods up to three years,
except options granted during 1997 and 1998 which are subject to a four year
vesting period.
16
<PAGE> 18
Stock option activity for the Company during 1996, 1997, 1998 and the
three month period ended March 31, 1999, was as follows:
<TABLE>
<CAPTION>
THREE MONTHS
ENDED
1996 1997 1998 MARCH 31, 1999
----------------------- ----------------------- ----------------------- -----------------------
WEIGHTED WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE EXERCISE
OPTIONS IN THOUSANDS OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
--------- ----------- ---------- ---------- ---------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Stock options outstanding,
beginning of year ......... 2,105 $ 2.38 4,589 $ 1.63 4,601 $ 1.75 4,497 $ 1.87
Granted ................. 2,520 1.01 482 2.61 727 2.20 -- --
Exercised ............... (36) 2.38 (415) 1.31 (272) 1.00 -- --
Surrendered or expired .. -- -- (55) 2.62 (559) 1.73 (482) 1.15
--------- --------- --------- ---------
Stock options outstanding,
end of year/period ........ 4,589 $ 1.63 4,601 $ 1.75 4,497 $ 1.87 4,015 $ 1.96
========= ========= ========= ========= ========= ========= ========= =========
</TABLE>
In February 1995, all previously issued options to the extent
outstanding, aggregating options to acquire 234,000 shares at prices ranging
from $7.00 to $7.63, were repriced at $4.13 per share. In February 1996, in
connection with the Contour Transaction, all unvested options then held by
employees were fully vested. Additionally, the then-existing plans were amended
to extend the period during which a terminated employee may exercise vested
options to three years after termination of employment.
At December 31, 1998 and March 31, 1999, approximately 3.6 million and
4.1 million shares, respectively, were available for future option grants.
The following table summarizes information about the options
outstanding at December 31, 1998:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------- --------------------------------
WEIGHTED
AVERAGE WEIGHTED
REMAINING WEIGHTED AVERAGE
RANGE OF OPTIONS CONTRACTUAL LIFE AVERAGE OPTIONS EXERCISE
EXERCISE PRICE (THOUSANDS) (YEARS) EXERCISE PRICE (THOUSANDS) PRICE
- --------------------- ------------- ----------------- ----------------- -------------- -------------
<S> <C> <C> <C> <C> <C>
$0.69 - 1.00 1,688 7.8 $1.00 793 $1.00
$1.75 - 2.56 2,531 7.2 2.25 1,808 2.23
$2.72 - 4.13 278 4.0 3.78 226 3.98
</TABLE>
17
<PAGE> 19
The following table summarizes information about the options outstanding at
March 31, 1999:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------- --------------------------------
WEIGHTED
AVERAGE WEIGHTED
REMAINING WEIGHTED AVERAGE
RANGE OF OPTIONS CONTRACTUAL LIFE AVERAGE OPTIONS EXERCISE
EXERCISE PRICE (THOUSANDS) (YEARS) EXERCISE PRICE (THOUSANDS) PRICE
- --------------------- ------------- ----------------- ----------------- -------------- -------------
<S> <C> <C> <C> <C> <C>
$0.69 - 1.00 1,252 7.2 $1.00 863 $1.00
$1.75 - 2.56 2,493 7.0 2.24 1,933 2.22
$2.72 - 4.13 270 3.6 3.81 224 3.99
</TABLE>
The weighted average fair value of options granted during 1996, 1997
and 1998 was $0.59, $1.51 and $1.46, respectively. There were no options granted
in the first quarter of 1999. The fair value of the options granted was
estimated on the date of grant using the Black-Scholes option-pricing model with
the following assumptions: weighted average risk-free interest rate of 6.8% for
1996, 6.4% for 1997 and 5.2% for 1998; an expected volatility of 60% for 1996
and 1997 and 78% for 1998; expected life of five years and no dividend yield for
all three years.
The Company applies Accounting Principles Board Opinion No. 25 and
related Interpretations in accounting for stock option and purchase plans.
Accordingly, no compensation cost has been recognized for the stock option
plans. Had compensation cost been recognized based upon the fair market value at
the grant dates for awards under those plans consistent with the method of
Statement of Financial Accounting Standards No. 123, "Accounting for Stock Based
compensation", the Company's net loss and earnings per share for the years ended
December 31, 1996, 1997, 1998 and the three month period ended March 31, 1999,
would have been as reflected in the pro forma amounts indicated below:
<TABLE>
<CAPTION>
THREE MONTHS
ENDED
1996 1997 1998 MARCH 31, 1999
----------- ---------- ---------- ----------------
<S> <C> <C> <C> <C>
Net income (loss) before
extraordinary item (in thousands)................ $ (14,512) $ 1,319 $ (57,708) $ (11,079)
Loss per common share
before extraordinary item........................ (.21) (.03) (.49) (.10)
Net income (loss)
(in thousands)................................... (31,542) $ 1,319 $ (57,708) $ (11,079)
Loss per common share................................ (.40) (.03) (.49) (.10)
</TABLE>
ESOP/401K. Kelley Oil established the ESOP effective January 1, 1984
for the benefit of substantially all of its employees. No ESOP contributions
were made in 1996. Effective September 1, 1996, the ESOP was amended to include
a 401(k) feature whereby the Company is obligated to make matching contributions
up to 6% of each employee's salary. The plan also provides for additional
discretionary contributions. For the years ended 1996, 1997, 1998 and the
periods ended March 31, 1998 (unaudited) and 1999, the Company made matching
contributions totaling $0.1 million, $0.2 million, $0.3 million, $58,000 and
$67,000, respectively.
18
<PAGE> 20
NOTE 7 - INCOME TAXES
The following table sets forth a reconciliation of the statutory
federal income tax for the years ended December 31, 1996, 1997 and 1998 and for
the three month period ended March 31, 1999:
(IN THOUSANDS)
<TABLE>
<CAPTION>
Three Months
ended
March 31,
1996 1997 1998 1999
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Income (loss) before income taxes ...... $ (28,965) $ 1,951 $ (57,007) $ (10,986)
----------- ----------- ----------- -----------
Income tax expense (benefit)
computed at statutory rates ......... (9,848) 663 (19,382) (3,735)
Increase in valuation allowance ..... 16,322 301 16,272 5,297
Adjustment to net operating loss
carryforward and other ............ (7,209) (1,459) 2,463 (1,778)
Permanent differences:
Nondeductible expenses .............. 735 708 700 216
Other-net ........................... -- (213) (53) --
----------- ----------- ----------- -----------
Tax expense (benefit) ............. $ -- $ -- $ -- $ --
=========== =========== =========== ===========
</TABLE>
No federal income taxes were paid for the years ended December 31,
1996, 1997 and 1998 or for the three months ended March 31, 1998 (unaudited) and
1999.
The Company's deferred tax position reflects the net tax effects of
temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax reporting.
Significant components of the deferred tax liabilities and assets are as
follows:
(IN THOUSANDS)
<TABLE>
<CAPTION>
Three Months
ended
March 31,
1996 1997 1998 1999
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Deferred tax liabilities:
Tax over book depletion, depreciation and
capitalization methods on oil and gas properties ..... $ -- $ -- $ -- $ --
Deferred tax assets:
Book over tax depletion, depreciation and
capitalization method on oil and gas properties ......... 42,696 32,210 43,730 44,096
Net operating loss carryforwards ........................ 62,179 72,992 77,741 82,672
Charitable contribution carryforwards ................... 78 52 54 54
Alternative minimum tax credit carryforwards ............ 21 21 21 21
Valuation allowance ..................................... (104,974) (105,275) (121,546) (126,843)
----------- ----------- ----------- -----------
Total deferred tax assets ............................... -- -- -- --
----------- ----------- ----------- -----------
Net deferred tax liability .............................. $ -- $ -- $ -- $ --
=========== =========== =========== ===========
</TABLE>
19
<PAGE> 21
Net Operating Loss Carryforwards and Alternative Minimum Tax Credits.
As of December 31, 1998, the Company had cumulative net operating loss
carryforwards ("NOL") for federal income tax purposes of approximately $228
million, which expire in 2000 through 2018, and net operating loss carryforwards
for alternative minimum tax purposes of approximately $218 million, which expire
in 2008 through 2018. Due to previous ownership changes, future utilization of
the net operating loss carry forwards will be limited by Internal Revenue Code
section 382.
NOTE 8 - RELATED PARTY TRANSACTIONS
The 1994 DDP. In February 1994, the 1994 DDP completed a public
offering of 20.9 million units of its limited and general partner interests at
$3.00 per unit. As of March 31, 1999, the Company owned 19.2 million units
(91.9%) in the 1994 DDP, together with its 3.94% general partner interest.
The 1994 DDP's partnership agreement provides that any contributions of
the partners not used or committed to be used for drilling activities during the
two-year period from the commencement of operations through February 29, 1996
(the "Commitment Period") shall be distributed to the partners on a pro rata
basis as a return of capital. In 1997, Kelley Oil reduced the estimate for
Committed Expenditures to $58.0 million based on the amount of committed capital
actually used and committed or allocated to drilling activities by the end of
the Commitment Period. In accordance with the 1994 DDP's partnership agreement,
the 1994 DDP distributed the Outside Share of uncommitted capital to its
unitholders other than Kelley Oil aggregating $0.3 million in March 1996 and
$0.1 million in July 1997.
The 1992 DDP. During November 1992, the 1992 DDP completed a public
offering of 16.0 million units of limited and general partner interests at $3.00
per unit. As of March 31, 1999, Kelley Oil owned 13.4 million units (83.7%) in
the 1992 DDP, together with its 3.94% general partner interest. As of March 31,
1999, the 1992 DDP was indebted to Kelley Oil for loans aggregating $2.3 million
($0.4 million, net of intercompany eliminations). The Company recorded interest
income on this indebtedness of $10,000 in the first three months of 1999, net of
intercompany eliminations.
Reimbursements from Affiliated Programs. The Company is reimbursed for
administrative and overhead expenses incurred in connection with the management
and administration of each of these affiliated programs. Such amounts, net of
intercompany eliminations, aggregated $0.2 million, $0.1 million, $21,000,
$24,000 and $18,000 in 1996, 1997, 1998, and the three months ended March 31,
1998 (unaudited) and 1999, respectively.
Interest on DDP Commitments. During 1996, 1997, 1998, the first three
months of 1998 (unaudited) and 1999, the Company paid or accrued interest at a
market rate in the amounts, net of intercompany elimination, of $91,000,
$11,000, zero, zero and zero, respectively, on deferred subscription commitments
to DDPs.
Advisory Fees. In connection with the Contour Transaction, the Company
entered into an agreement (the "Advisory Agreement") with Bessemer Partners &
Co. ("BPCO"), an affiliate of Bessemer, providing for the engagement of BPCO to
provide the Company with financial advisory services. Under the Advisory
Agreement, BPCO has assisted the Company in arranging a new credit facility and
negotiating the related agreements and is assisting the Company in restructuring
its current capital structure. For its services under the Advisory Agreement,
BPCO received an advisory fee of $2.0 million at the closing of the Contour
Transaction and $500,000 in each of December 1996, 1997 and 1998, and will
receive an additional $500,000 in each December of 1999, 2000 and 2001. In
addition, BPCO is entitled to reimbursement of expenses incurred in connection
with rendering advisory services. The Company also has agreed to indemnify BPCO
and its affiliates against certain liabilities under the Advisory Agreement.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
Significant Customers. Substantially all of the Company's receivables
are due from a limited number of natural gas transmission companies and other
gas purchasers. During 1998 and the three month period ended March 31, 1999,
natural gas sales to three purchasers accounted for 48%, 22% and 18% and
20
<PAGE> 22
50%, 25% and 17%, respectively, of the Company's total sales. To date, this
concentration has not had a material adverse effect on the consolidated
financial condition of the Company.
Litigation. As previously disclosed, following Kelley Oil's
announcement of the initial proposal for the Consolidation in August 1994, four
separate lawsuits were filed against Kelley Oil and its directors relating to
the Consolidation. In November 1994, Kelley Oil entered into a memorandum of
understanding with the plaintiffs in three of the lawsuits, providing for a
proposed settlement based on a revised Consolidation proposal negotiated by a
special committee of Kelley Oil's non-management directors and the settling
plaintiffs. A stipulation and agreement of compromise, settlement and release
reflecting the terms of the proposed settlement was filed in the United States
District Court for the Southern District of Texas on November 23, 1994. At a
hearing held on the same date, the court approved the Consolidation of all four
lawsuits and the certification of a Unitholder class requested by the settling
parties. On March 3, 1995, following a hearing on the fairness of the
settlement, the court entered a final order approving the settlement, dismissing
the consolidated lawsuits with prejudice and reducing the award of attorneys'
fees and disbursements contemplated by the stipulation to $1.5 million, plus
interest from March 3, 1995 through the payment date. On April 29, 1997, the
U.S. Court of Appeals for the Fifth Circuit affirmed the final judgement and
order of the District Court. On August 4, 1997, the Company made a cash payment
of $1.7 million which included $0.2 million of interest.
The Company is involved in various claims and lawsuits incidental to
its business. In the opinion of management, the ultimate liability thereunder,
if any, will not have a material effect on the financial statements of the
Company.
Restructuring Expenses. In 1996, the Company incurred restructuring
expenses of $4.3 million associated primarily with staff reductions, related
severance settlements and reorganization costs. Accrued expenses on the balance
sheet include $0.9 million, $0.2 million and $0.1 million at December 31, 1997
and 1998 and March 31, 1999, respectively, related to the unpaid portion of
these charges.
Leases. The Company leases office space and equipment under operating
leases with options to renew. Rental expenses related to these leases for the
years ended December 31, 1996, 1997 and 1998 and for the three month periods
ended March 31, 1998 (unaudited) and 1999 were $1.3 million, $0.8 million, $0.6
million, $0.1 million and $0.2 million, respectively. For the balance of the
lease terms, minimum rentals are as follows:
(IN THOUSANDS)
<TABLE>
<S> <C>
1999.................................................................... $ 667
2000.................................................................... 636
2001 ................................................................... 341
2002 ................................................................... 39
2003.................................................................... 7
-------
Total................................................................... $ 1,690
=======
</TABLE>
The terms of the Company's office space lease provide that the Company
may terminate its rental obligation upon six months notice and incurring a
maximum obligation of $0.2 million.
NOTE 10 - HEDGING ACTIVITIES
The Company periodically uses forward sales contracts, natural gas
price swap agreements, natural gas basis swap agreements and options to reduce
exposure to downward price fluctuations on its natural gas production. The
Company does not engage in speculative transactions. During 1998, the Company
used price and basis swap agreements. Price swap agreements generally provide
for the Company to receive or make counterparty payments on the differential
between a fixed price and a variable indexed price for natural gas. Basis swap
agreements generally provide for the Company to receive or make counterparty
payments on the differential between a variable indexed price and the price it
receives from the sale of natural gas production, and are used to hedge against
unfavorable price movements in the relationship between such variable indexed
price and the price received for such production. Gains and losses realized by
the Company from hedging activities are included in oil and gas revenues and
average sales prices in the period that the related production is sold. The
Company's hedging activities also
21
<PAGE> 23
cover the oil and gas production attributable to the interest in such production
of the public unitholders in its subsidiary partnerships.
Through natural gas price swap agreements, the Company hedged
approximately 49% and 66% of its natural gas production for 1998 and the three
month period ended March 31, 1999, respectively, at average NYMEX quoted prices
of $2.31 per Mmbtu and $2.27 per Mmbtu, respectively, before transaction and
transportation costs. As of December 31, 1998, 5,400,000 Mmbtus of natural gas
production for 1999 has been hedged by natural gas price swap agreements at an
average NYMEX quoted price of $2.36 per Mmbtu before transaction and
transportation costs. As of March 31, 1999, 5,630,000 Mmbtus of natural gas
production for April through October 1999 has been hedged by natural gas price
swap agreements at an average NYMEX quoted price of $2.03 per Mmbtu before
transaction and transportation costs. As of December 31, 1998, 16,380,000
Mmbtu's of natural gas production for 1999 has been hedged by natural gas basis
swap agreements. As of March 31, 1999, 10,980,000 Mmbtus of natural gas
production for April through September 1999 has been hedged by natural gas basis
swap agreements. Hedging activities increased revenues by approximately $3.5
million in 1998 and $2.5 million in the first quarter of 1999, as compared to
estimated revenues had no hedging activities been conducted. At December 31,
1998, the unrealized gain on the Company's existing hedging instruments for
future production months in 1999 approximated $2.5 million. As of March 31,
1999, the unrealized loss on the Company's existing hedging instruments for the
future production months in 1999 approximated $1.4 million.
The credit risk exposure from counterparty nonperformance on natural
gas forward sales contracts and derivative financial instruments is generally
the amount of unrealized gains under the contracts. The Company has not
experienced counterparty nonperformance on these agreements and does not
anticipate any in future periods.
22
<PAGE> 24
NOTE 11 - GUARANTOR FINANCIAL STATEMENTS
Kelley Oil Corporation, a wholly-owned subsidiary of the Company and
Kelley Operating Company Ltd., an indirect wholly-owned partnership of the
Company are guarantors of the Company's Series B and Series D 10 3/8 % Senior
Subordinated Notes due 2006. The following guarantor consolidating condensed
financial statements present:
1. Consolidating condensed balance sheets as of December 31, 1997 and
1998 and March 31, 1999, consolidating condensed statements of
income (loss) for each of the years ended December 31, 1996, 1997
and 1998 and for the three month periods ended March 31, 1998
(unaudited) and 1999 and consolidating condensed statements of
cash flows for each of the years ended December 31, 1996, 1997 and
1998 and for the three month periods ended March 31, 1998
(unaudited) and 1999.
2. Kelley Oil & Gas Corporation (the "Parent"), combined Guarantor
Subsidiaries and combined Non-Guarantor Subsidiaries, all with
their investments in subsidiaries accounted for using the equity
method.
3. Elimination entries necessary to consolidate the Parent and all of
its subsidiaries.
23
<PAGE> 25
CONSOLIDATING CONDENSED BALANCE SHEET
DECEMBER 31, 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
ASSETS:
Current assets ........................ $ 427,445 $ 212,780 $ 18,926 $ (632,293) $ 26,858
Property and equipment, net ........... -- 276,744 17,698 (829) 293,613
Other non-current assets, net ......... (141,957) 24,418 -- 119,670 2,131
------------- ------------- ------------- ------------- -------------
Total assets ........................ $ 285,488 $ 513,942 $ 36,624 $ (513,452) $ 322,602
============= ============= ============= ============= =============
LIABILITIES AND STOCKHOLDERS' DEFICIT:
Current liabilities ................... $ 4,926 $ 657,128 $ 12,279 $ (632,293) $ 42,040
Long-term debt ........................ 286,183 -- -- -- 286,183
Stockholders' deficit ................. (5,621) (143,186) 24,345 118,841 (5,621)
------------- ------------- ------------- ------------- -------------
Total liabilities and
stockholders' deficit ........... $ 285,488 $ 513,942 $ 36,624 $ (513,452) $ 322,602
============= ============= ============= ============= =============
</TABLE>
CONSOLIDATING CONDENSED BALANCE SHEET
DECEMBER 31, 1998
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
ASSETS:
Current assets ........................ $ 424,609 $ 212,946 $ 10,859 $ (620,163) $ 28,251
Property and equipment, net ........... -- 243,927 14,008 (1,480) 256,455
Other non-current assets, net ......... (165,642) 18,611 -- 148,522 1,491
------------- ------------- ------------- ------------- -------------
Total assets ........................ $ 258,967 $ 475,484 $ 24,867 $ (473,121) $ 286,197
============= ============= ============= ============= =============
LIABILITIES AND STOCKHOLDERS' DEFICIT:
Current liabilities ................... $ 38,406 $ 641,113 $ 6,281 $ (620,164) $ 65,636
Long-term debt ........................ 287,500 -- -- -- 287,500
Stockholders' deficit ................. (66,939) (165,629) 18,586 147,043 (66,939)
------------- ------------- ------------- ------------- -------------
Total liabilities and
stockholders' deficit ........... $ 258,967 $ 475,484 $ 24,867 $ (473,121) $ 286,197
============= ============= ============= ============= =============
</TABLE>
24
<PAGE> 26
CONSOLIDATING CONDENSED BALANCE SHEET
MARCH 31, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
ASSETS:
Current assets ........................ $ 422,192 $ 206,289 $ 8,166 $ (610,670) $ 25,977
Property and equipment, net ........... -- 239,052 13,589 (1,677) 250,964
Other non-current assets, net ......... (168,126) 18,476 -- 150,948 1,298
------------- ------------- ------------- ------------- -------------
Total assets ........................ $ 254,066 $ 463,817 $ 21,755 $ (461,399) $ 278,239
============= ============= ============= ============= =============
LIABILITIES AND STOCKHOLDERS' DEFICIT:
Current liabilities ................... $ 44,032 $ 631,533 $ 3,310 $ (610,670) $ 68,205
Long-term debt ........................ 287,959 -- -- -- 287,959
Stockholders' deficit ................. (77,925) (167,716) 18,445 149,271 (77,925)
------------- ------------- ------------- ------------- -------------
Total liabilities and
stockholders' deficit ............... $ 254,066 $ 463,817 $ 21,755 $ (461,399) $ 278,239
============= ============= ============= ============= =============
</TABLE>
25
<PAGE> 27
CONSOLIDATING CONDENSED STATEMENT OF INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 1996
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Revenues ................................. $ -- $ 39,248 $ 24,784 $ (1,749) $ 62,283
Costs and expenses ....................... (22,397) (39,293) (13,150) 623 (74,217)
Equity in earnings of subsidiaries ....... 10,463 11,634 -- (22,097) --
Extraordinary item ....................... (17,030) -- -- -- (17,030)
------------- ------------- ------------- ------------- -------------
Net income (loss) ........................ $ (28,964) $ 11,589 $ 11,634 $ (23,223) $ (28,964)
============= ============= ============= ============= =============
</TABLE>
CONSOLIDATING CONDENSED STATEMENT OF INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Revenues ................................. $ 8 $ 57,064 $ 19,508 $ (442) $ 76,138
Costs and expenses ....................... (27,196) (36,975) (10,329) 313 (74,187)
Equity in earnings of subsidiaries ....... 29,139 9,179 -- (38,318) --
------------- ------------- ------------- ------------- -------------
Net income (loss) ........................ $ 1,951 $ 29,268 $ 9,179 $ (38,447) $ 1,951
============= ============= ============= ============= =============
</TABLE>
CONSOLIDATING CONDENSED STATEMENT OF INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 1998
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Revenues ................................. $ (18) $ 69,958 $ 9,715 $ -- $ 79,655
Costs and expenses ....................... (33,893) (94,457) (7,742) (570) (136,662)
Equity in earnings (loss)
of subsidiaries ........................ (23,096) 1,973 -- 21,123 --
------------- ------------- ------------- ------------- -------------
Net income (loss) ........................ $ (57,007) $ (22,526) $ 1,973 $ 20,553 $ (57,007)
============= ============= ============= ============= =============
</TABLE>
26
<PAGE> 28
CONSOLIDATING CONDENSED STATEMENT OF INCOME
FOR THE THREE MONTHS ENDED MARCH 31, 1998
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Revenues ................................. $ (18) $ 19,962 $ 3,194 $ (67) $ 23,071
Expenses ................................. (8,260) (17,940) (1,940) 246 (27,894)
Equity in earnings of subsidiaries ....... 3,455 1,254 -- (4,709) --
------------- ------------- ------------- ------------- -------------
Net income (loss) ........................ $ (4,823) $ 3,276 $ 1,254 $ (4,530) $ (4,823)
============= ============= ============= ============= =============
</TABLE>
CONSOLIDATING CONDENSED STATEMENT OF INCOME
FOR THE THREE MONTHS ENDED MARCH 31, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Revenues ................................. $ -- $ 13,732 $ 1,990 $ (54) $ 15,668
Expenses ................................. (8,701) (16,684) (1,125) (144) (26,654)
Equity in earnings (loss) of subsidiaries (2,285) 865 -- 1,420 --
------------- ------------- ------------- ------------- -------------
Net income (loss) ........................ $ (10,986) $ (2,087) $ 865 $ 1,222 $ (10,986)
============= ============= ============= ============= =============
</TABLE>
27
<PAGE> 29
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1996
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) ..................... $ (28,964) $ 11,589 $ 11,634 $ (23,223) $ (28,964)
Non-cash income (loss)
adjustments ......................... 10,133 12,280 6,542 23,223 52,178
Changes in operating assets
and liabilities ..................... (31,460) 26,767 (9,259) -- (13,952)
------------- ------------- ------------- ------------- -------------
Net cash provided by (used in)
operating activities ................ (50,291) 50,636 8,917 -- 9,262
------------- ------------- ------------- ------------- -------------
INVESTING ACTIVITIES:
Capital expenditures .................. -- (35,203) (12,398) -- (47,601)
Acquisition of oil and gas
properties .......................... -- (11,594) -- -- (11,594)
Proceeds from sale of properties ...... -- 3,811 1,992 -- 5,803
------------- ------------- ------------- ------------- -------------
Net cash used in investing
activities ............................ -- (42,986) (10,406) -- (53,392)
------------- ------------- ------------- ------------- -------------
FINANCING ACTIVITIES:
Net payments on long term
borrowings .......................... -- (8,500) -- -- (8,500)
Proceeds from sale of notes,
net ................................. 120,938 -- -- -- 120,938
Debenture conversion costs ............ (1,100) -- -- -- (1,100)
Proceeds from sale of
common stock, net ................... 43,998 -- -- -- 43,998
Retirement of senior notes ............ (113,488) -- -- -- (113,488)
------------- ------------- ------------- ------------- -------------
Net cash provided by (used in)
financing activities ................ 50,348 (8,500) -- -- 41,848
------------- ------------- ------------- ------------- -------------
Increase (decrease) in cash and
cash equivalents .................... 57 (850) (1,489) -- (2,282)
Cash and cash equivalents,
beginning of period ................. 1 3,654 2,697 -- 6,352
------------- ------------- ------------- ------------- -------------
Cash and cash equivalents, end of
period ................................ $ 58 $ 2,804 $ 1,208 $ -- $ 4,070
============= ============= ============= ============= =============
</TABLE>
28
<PAGE> 30
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income ................................ $ 1,951 $ 29,268 $ 9,179 $ (38,447) $ 1,951
Non-cash income (loss) adjustments ........ (24,842) 16,880 5,098 38,447 35,583
Changes in operating assets
and liabilities ......................... (97,813) 105,584 (5,701) -- 2,070
------------- ------------- ------------- ------------- -------------
Net cash provided by (used in)
operating activities ...................... (120,704) 151,732 8,576 -- 39,604
------------- ------------- ------------- ------------- -------------
INVESTING ACTIVITIES:
Capital expenditures ...................... -- (51,592) (1,548) -- (53,140)
Acquisition of oil and gas properties ..... -- (111,135) -- -- (111,135)
Capital contributed to partnerships ....... -- (5,819) -- 5,819 --
Distributions from partnerships ........... -- 14,014 -- (14,014) --
------------- ------------- ------------- ------------- -------------
Net cash used in investing activities ........ -- (154,532) (1,548) (8,195) (164,275)
------------- ------------- ------------- ------------- -------------
FINANCING ACTIVITIES:
Net proceeds on long term borrowings ...... 97,800 -- -- -- 97,800
Proceeds from sale of common stock, net ... 27,545 -- -- -- 27,545
Distributions to partners ................. -- -- (14,014) 14,014 --
Capital contributed by partners ........... -- -- 5,819 (5,819) --
Dividends on preferred stock .............. (4,582) -- -- -- (4,582)
------------- ------------- ------------- ------------- -------------
Net cash provided by (used in) financing
activities ................................ 120,763 -- (8,195) 8,195 120,763
------------- ------------- ------------- ------------- -------------
Increase (decrease) in cash
and cash equivalents ...................... 59 (2,800) (1,167) -- (3,908)
Cash and cash equivalents,
beginning of period ....................... 58 2,804 1,208 -- 4,070
------------- ------------- ------------- ------------- -------------
Cash and cash equivalents,
end of period ............................. $ 117 $ 4 $ 41 $ -- $ 162
============= ============= ============= ============= =============
</TABLE>
29
<PAGE> 31
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1998
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) ......................... $ (57,007) $ (22,526) $ 1,973 $ 20,553 $ (57,007)
Non-cash income (loss) adjustments ........ 28,109 70,144 3,687 (20,553) 81,387
Changes in operating assets
and liabilities ......................... 3,869 (7,976) 2,029 -- (2,078)
------------- ------------- ------------- ------------- -------------
Net cash provided by (used in)
operating activities ...................... (25,029) 39,642 7,689 -- 22,302
------------- ------------- ------------- ------------- -------------
INVESTING ACTIVITIES:
Capital expenditures ...................... -- (56,579) -- -- (56,579)
Proceeds from sale of property ............ -- 17,363 -- -- 17,363
Distributions from partnerships ........... -- 7,730 -- (7,730) --
------------- ------------- ------------- ------------- -------------
Net cash used in investing activities ........ -- (31,486) -- (7,730) (39,216)
------------- ------------- ------------- ------------- -------------
FINANCING ACTIVITIES:
Payments on long term borrowings .......... (118,900) -- -- -- (118,900)
Net proceeds on long term borrowings ...... 119,100 -- -- -- 119,100
Redemption on subordinated notes .......... (228) -- -- -- (228)
Proceeds from sale of common stock ........ 273 -- -- -- 273
Proceeds from conversion of preferred ..... (2) -- -- -- (2)
Proceeds from sale of common stock, net ... 29,526 -- -- -- 29,526
Distributions to partners ................. -- -- (7,730) 7,730 --
Dividends on preferred stock .............. (4,582) -- -- -- (4,582)
------------- ------------- ------------- ------------- -------------
Net cash provided by (used in) financing
activities ................................ 25,187 -- (7,730) 7,730 25,187
------------- ------------- ------------- ------------- -------------
Increase (decrease) in cash
and cash equivalents ...................... 158 8,156 (41) -- 8,273
Cash and cash equivalents,
beginning of period ....................... 117 4 41 -- 162
------------- ------------- ------------- ------------- -------------
Cash and cash equivalents,
end of period ............................. $ 275 $ 8,160 $ -- $ -- $ 8,435
============= ============= ============= ============= =============
</TABLE>
30
<PAGE> 32
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31, 1998
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income ................................ $ (4,823) $ 3,276 $ 1,254 $ (4,530) $ (4,823)
Non-cash income adjustments ............... (2,061) 11,041 879 4,530 14,389
Changes in operating assets
and liabilities ......................... 3,721 (3,848) 247 -- 120
------------- ------------- ------------- ------------- -------------
Net cash provided by (used in)
operating activities ...................... (3,163) 10,469 2,380 -- 9,686
------------- ------------- ------------- ------------- -------------
INVESTING ACTIVITIES:
Capital expenditures ...................... -- (12,675) (206) -- (12,881)
Capital contributed to partnerships ....... -- -- -- -- --
Distributions from partnerships ........... -- 2,202 -- (2,202) --
------------- ------------- ------------- ------------- -------------
Net cash used in investing activities ........ -- (10,473) (206) (2,202) (12,881)
------------- ------------- ------------- ------------- -------------
FINANCING ACTIVITIES:
Net proceeds on long term borrowings ...... 34,100 -- -- -- 34,100
Net payments on long term borrowings ...... (30,800) -- -- -- (30,800)
Redemption of notes ....................... (228) -- -- -- (228)
Proceeds from sale of common stock, net ... 1 -- -- -- 1
Distributions to partners ................. -- -- (2,202) 2,202 --
Capital contributed by partners ........... -- -- -- -- --
Dividends on preferred stock .............. -- -- -- -- --
------------- ------------- ------------- ------------- -------------
Net cash provided by (used in) financing
activities ................................ 3,073 -- (2,202) 2,202 3,073
------------- ------------- ------------- ------------- -------------
Decrease in cash and cash equivalents ........ (90) (4) (28) -- (122)
Cash and cash equivalents,
beginning of period ....................... 117 4 41 -- 162
------------- ------------- ------------- ------------- -------------
Cash and cash equivalents,
end of period ............................. $ 27 $ -- $ 13 $ -- $ 40
============= ============= ============= ============= =============
</TABLE>
31
<PAGE> 33
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMBINED COMBINED
GUARANTOR NON-GUARANTOR
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) ......................... $ (10,986) $ (2,087) $ 865 $ 1,222 $ (10,986)
Non-cash income (loss) adjustments ........ 3,517 9,835 433 (1,222) 12,563
Changes in operating assets
and liabilities ......................... 7,188 (4,370) (297) -- 2,521
------------- ------------- ------------- ------------- -------------
Net cash provided by (used in)
operating activities ...................... (281) 3,378 1,001 -- 4,098
------------- ------------- ------------- ------------- -------------
INVESTING ACTIVITIES:
Capital expenditures ...................... -- (5,823) -- -- (5,823)
Proceeds from sale of property ............ -- -- -- -- --
Distributions from partnerships ........... -- 1,001 -- (1,001) --
------------- ------------- ------------- ------------- -------------
Net cash used in investing activities ........ -- (4,822) -- (1,001) (5,823)
------------- ------------- ------------- ------------- -------------
FINANCING ACTIVITIES:
Net payments on long term borrowings ...... -- -- -- -- --
Proceeds from sale of notes, net .......... -- -- -- -- --
Redemption of subordinated notes .......... -- -- -- -- --
Proceeds from sale of common stock, net ... -- -- -- -- --
Proceeds from conversion of
preferred stock ......................... -- -- -- -- --
Distributions to partners ................. -- -- (1,001) 1,001 --
Dividends on preferred stock .............. -- -- -- -- --
------------- ------------- ------------- ------------- -------------
Net cash provided by (used in) financing
activities ................................ -- -- (1,001) 1,001
------------- ------------- ------------- ------------- -------------
Increase (Decrease) in cash and cash
equivalents ............................... (281) (1,444) -- -- (1,725)
Cash and cash equivalents,
beginning of period ....................... 275 8,160 -- -- 8,435
------------- ------------- ------------- ------------- -------------
Cash and cash equivalents,
end of period ............................. $ (6) $ 6,716 $ -- $ -- $ 6,710
============= ============= ============= ============= =============
</TABLE>
32
<PAGE> 34
NOTE 12 - SUPPLEMENTARY FINANCIAL AND OPERATING INFORMATION ON OIL AND GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This footnote provides unaudited information required by Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities".
Capitalized Costs. Capitalized costs and accumulated depreciation,
depletion and amortization relating to the Company's oil and gas producing
activities, all of which are conducted within the continental United States, are
summarized below.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1996 1997 1998
---------- ---------- ----------
<S> <C> <C> <C>
Unevaluated properties ..................................... $ 12,521 $ 49,854 $ 38,293
Properties subject to amortization ......................... 338,794 463,263 496,686
---------- ---------- ----------
Capitalized costs .......................................... 351,315 513,117 534,979
Accumulated depreciation, depletion and amortization ....... (194,367) (221,729) (280,640)
---------- ---------- ----------
Net capitalized costs ...................................... $ 156,948 $ 291,388 $ 254,339
========== ========== ==========
</TABLE>
Costs Incurred. Costs incurred in oil and gas property acquisition,
exploration and development activities are summarized below.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1996 1997 1998
---------- ---------- ----------
<S> <C> <C> <C>
Property acquisition costs:
Proved .................................................. $ 11,594 $ 73,190 $ 2,338
Unproved (1) ............................................ 2,160 40,997 1,405
Exploration costs .......................................... 5,438 9,525 25,414
Development costs .......................................... 41,790 40,713 27,875
---------- ---------- ----------
Total costs incurred .................................... $ 60,982 $ 164,425 $ 57,032
========== ========== ==========
</TABLE>
(1) Includes $40 million in unproved assets acquired from SPR on December
1, 1997.
33
<PAGE> 35
Reserves. The following table summarizes the Company's net ownership
interests in estimated quantities of proved oil and gas reserves and changes in
net proved reserves, all of which are located in the continental United States,
for the years ended December 31, 1996, 1997 and 1998. Reserves estimates
contained below were prepared by H.J. Gruy & Associates, Inc. ("Gruy"),
independent petroleum engineers.
<TABLE>
<CAPTION>
CRUDE OIL, CONDENSATE
AND NATURAL GAS LIQUIDS NATURAL GAS
(MBBLS) (MMCF)
-------------------------------------- --------------------------------------
1996 1997 1998 1996 1997 1998
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year ................ 1,387 1,466 2,953 196,273 297,634 354,867
Revisions of previous estimates .. (89) 106 (79) (30,519) 21,831 (31,674)
Purchases of reserves in place ... 57 1,351 -- 30,844 51,712 --
Extensions and discoveries ....... 477 256 3,082 128,692 13,892 9,512
Sale of reserves in place ........ (134) -- (287) (4,190) -- (13,589)
Production ....................... (232) (226) (375) (23,466) (30,202) (35,557)
---------- ---------- ---------- ---------- ---------- ----------
End of year ...................... 1,466 2,953 5,294 297,634 354,867 283,559
========== ========== ========== ========== ========== ==========
Proved developed reserves
at end of year ................... 977 2,432 1,981 173,465 257,800 188,824
========== ========== ========== ========== ========== ==========
</TABLE>
Standardized Measure. The following table of the Standardized Measure
of Discounted Future Net Cash Flows concerning the standardized measure of
future cash flows from proved oil and gas reserves are presented in accordance
with Statement of Financial Accounting Standards No. 69. As prescribed by this
statement, the amounts shown are based on prices and costs at the end of each
period, and assume continuation of existing economic conditions. Future income
taxes are based on year-end statutory rates, adjusted for operating loss
carryforwards and tax credits. A discount factor of 10% was used to reflect the
timing of future net cash flow. Extensive judgments are involved in estimating
the timing of production and the costs that will be incurred throughout the
remaining lives of the fields. Accordingly, the estimates of future net revenues
from proved reserves and the present value thereof may not be materially correct
when judged against actual subsequent results. Further, since prices and costs
do not remain static, and no price or cost changes have been considered, and
future production and development costs are estimates to be incurred in
developing and producing the estimated proved oil and gas reserves, the results
are not necessarily indicative of the fair market value of estimated proved
reserves, and the results may not be comparable to estimates disclosed by other
oil and gas producers.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1996 1997 1998
----------- ----------- -----------
<S> <C> <C> <C>
Future cash inflows ............................................. $ 1,099,089 $ 930,357 $ 643,473
Future production costs ......................................... (113,178) (196,048) (159,378)
Future development costs ........................................ (81,932) (106,123) (93,321)
Future income tax expenses ...................................... (162,887) (37,050) (1,627)
----------- ----------- -----------
Future net cash flows ....................................... 741,092 591,136 389,147
10% annual discount for estimating timing of cash flows ......... (307,321) (227,249) (155,677)
----------- ----------- -----------
Standardized measure of discounted future net cash flows .... $ 433,771 $ 363,887 $ 233,470
=========== =========== ===========
</TABLE>
The standardized measure of discounted future net cash flows as of
December 31, 1996, 1997 and 1998 was calculated using prices in effect as of
those dates, which averaged $25.18, $16.93 and $10.81, respectively, per barrel
of oil and $3.66, $2.49 and $2.07, respectively, per Mcf of natural gas.
34
<PAGE> 36
Change in Standardized Measure. Changes in standardized measure of
future net cash flows relating to proved oil and gas reserves are summarized
below.
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1996 1997 1998
------------ ------------ ------------
<S> <C> <C> <C>
Changes due to current year operations:
Sales of oil and gas, net of production costs ................ $ (48,307) $ (62,080) $ (57,940)
Sale of reserves in place .................................... (6,836) -- (15,424)
Extensions and discoveries ................................... 192,174 21,945 20,097
Purchases of reserves in place ............................... 11,594 91,034 --
Future development costs incurred ............................ 24,500 21,806 9,218
Changes due to revisions in standardized variables:
Prices and production costs .................................. 159,292 (243,851) (94,569)
Revisions of previous quantity estimates ..................... (50,594) 25,345 (29,853)
Estimated future development costs ........................... 3,254 (17,413) (29,240)
Income taxes ................................................. (82,831) 69,489 (14,110)
Accretion of discount ........................................ 17,575 51,818 24,903
Production rates (timing) and other .......................... 42,898 (27,977) 56,501
------------ ------------ ------------
Net increase (decrease) .................................... 262,719 (69,884) (130,417)
Beginning of year ............................................ 171,052 433,771 363,887
------------ ------------ ------------
End of year ................................................ $ 433,771 $ 363,887 $ 233,470
============ ============ ============
</TABLE>
Sales of oil and gas, net of production costs, are based on historical
pre-tax results. Extensions and discoveries, purchases of reserves in place and
the changes due to revisions in standardized variables are reported on a pre-tax
discounted basis, while the accretion of discount is presented after tax.
Extensions and discoveries include proved undeveloped reserves attributable to
Kelley Oil's interests in drill sites assigned to DDPs.
NOTE 13 - QUARTERLY RESULTS (UNAUDITED)
<TABLE>
<CAPTION>
1997 1998
---------------------------------------- -----------------------------------------
1ST 2ND 3RD 4TH (1) 1ST 2ND 3RD 4TH(2)
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
--------- -------- ------- ------- --------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues.............................. $ 18,947 16,178 17,105 23,634 $ 23,047 21,162 18,630 16,311
Operating profit...................... 7,368 4,892 6,121 8,367 3,245 (1,251) (85) (26,087)
Net income (loss)..................... 1,703 (1,248) 59 1,437 (4,823) (9,433) (8,411) (34,340)
Basic and diluted income
(loss) per common share........... $ 0.01 (0.02) (0.01) -- $ (0.05) (0.08) (0.08) (0.28)
</TABLE>
(1) Reflects the acquisition of SPR on December 1, 1997.
(2) Reflects non-cash impairment charges against the carrying value of proved
and unproved oil and natural gas properties under SFAS 121 (see Note 2).
35
<PAGE> 37
SECTION B. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following information should be read in conjunction with the
information contained in the Financial Statements of the Company included
elsewhere in this Report.
GENERAL
Introduction. Kelley Oil & Gas Corporation and its consolidated
subsidiaries (the "Company") are engaged in oil and natural gas exploration,
development, production and acquisition. The Company's 1998 operational
activities were focused primarily on exploiting its north Louisiana properties
and exploration activities on its south Louisiana acreage. In 1998, the Company
drilled or participated in drilling 47 gross (21.2 net) development wells and 15
gross (5.8 net) exploratory wells of which 46 gross (20.7 net) and 8 gross (2.5
net), respectively, were completed as producing wells. The Company's most
significant event was the drilling of the Harry S. Bourg #1 discovery well in
Terrebonne Parish, Louisiana which added 21.4 bcfe of proved reserves to the
Company's reserve base at year-end. The Company has a 50% working interest in
this well. In the first three months of 1999, the Company participated in
drilling 2 gross (0.5 net) wells, both of which were completed in the first
quarter of 1999.
General Conditions of the Oil and Natural Gas Industry and Commodity
Prices. Through the first quarter of 1999, the prices of oil and natural gas
during recent months have fallen sharply and continue to reflect the volatility
of commodity prices and the industry generally. The Company cannot predict
future prices of oil and natural gas. Although both oil and natural gas prices
have recovered, should prices decline, the Company's results of operations and
liquidity could be adversely impacted. The success of the Company is in part
dependent on factors outside the control of the Company, but which directly
affect the financial condition of the Company, including capital market
conditions and highly volatile oil and natural gas prices. Due to recent
industry conditions, the Company, as others within the industry, has been
required to reconsider its capital expenditures budgets, which could adversely
impact production levels, and to evaluate various financing and strategic
alternatives.
Hedging Activities. The Company periodically uses forward sales
contracts, natural gas price swap agreements, natural gas basis swap agreements
and options to reduce exposure to downward price fluctuations on its natural gas
production. The Company does not engage in speculative transactions. During
1998, the Company used price and basis swap agreements. Price swap agreements
generally provide for the Company to receive or make counterparty payments on
the differential between a fixed price and a variable indexed price for natural
gas. Basis swap agreements generally provide for the Company to receive or make
counterparty payments on the differential between a variable indexed price and
the price it receives from the sale of natural gas production, and are used to
hedge against unfavorable price movements in the relationship between such
variable indexed price and the price received for such production. Gains and
losses realized by the Company from hedging activities are included in oil and
gas revenues and average sales prices in the period that the related production
is sold. The Company's hedging activities also cover the oil and gas production
attributable to the interest in such production of the public unitholders in its
subsidiary partnerships.
Through natural gas price swap agreements, the Company hedged
approximately 49% and 66% of its natural gas production for 1998 and the three
month period ended March 31, 1999, respectively, at average NYMEX quoted prices
of $2.31 per Mmbtu and $2.27 per Mmbtu, respectively, before transaction and
transportation costs. As of December 31, 1998, 5,400,000 Mmbtus of natural gas
production for 1999 has been hedged by natural gas price swap agreements at an
average NYMEX quoted price of $2.36 per Mmbtu before transaction and
transportation costs. As of March 31, 1999, 5,630,000 Mmbtus of natural gas
production for April through October 1999 has been hedged by natural gas price
swap agreements at an average NYMEX quoted price of $2.03 per Mmbtu before
transaction and transportation costs. As of December 31, 1998, 16,380,000
Mmbtu's of natural gas production for 1999 has been hedged by natural gas basis
swap agreements. As of March 31, 1999, 10,980,000 Mmbtus of natural gas
production for April through September 1999 has been hedged by natural gas basis
swap agreements. Hedging activities increased revenues by approximately $3.5
million in 1998 and $2.5 million in the first quarter of 1999, as compared to
estimated revenues had no hedging activities been conducted. At December 31,
1998, the unrealized gain on the Company's existing hedging instruments for
future production
36
<PAGE> 38
months in 1999 approximated $2.5 million. As of March 31, 1999, the unrealized
loss on the Company's existing hedging instruments for the future production
months in 1999 approximated $1.4 million.
The credit risk exposure from counterparty nonperformance on natural
gas forward sales contracts and derivative financial instruments is generally
the amount of unrealized gains under the contracts. The Company has not
experienced counterparty nonperformance on these agreements and does not
anticipate any in future periods.
RESULTS OF OPERATIONS
The following table sets forth certain operating data regarding
net production, average sales prices, production expenses and revenues
associated with the Company's oil and natural gas operations for the periods
indicated.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------------
1998 1999
------------ ------------
<S> <C> <C>
NET PRODUCTION DATA:
Oil and other liquid hydrocarbons (Mbbls) ........................... 102 82.8
Natural gas (Mmcf) .................................................. 10,165 7,247
Natural gas equivalent (Mmcfe) ...................................... 10,777 7,744
AVERAGE SALES PRICE PER UNIT:
Oil and other liquid hydrocarbons (per Bbl) ......................... $ 14.26 $ 11.63
Natural gas (per Mcf) ............................................... 2.12 1.97
Natural gas equivalent (per Mcfe) ................................... 2.13 1.97
COST PER MCFE:
Lifting costs ....................................................... $ .34 $ .59
Severance and ad valorem taxes ...................................... .12 .10
General and administrative expenses ................................. .18 .18
Depreciation, depletion and amortization (oil and gas activities) ... 1.00 1.20
Interest expense, excluding accretion and amortization .............. .62 .96
</TABLE>
The Company's oil and gas revenues of $15.5 million for the first
quarter of 1999 decreased 33% compared to $23.0 million in the same period of
1998 as a result of a decrease in natural gas production (29%), decreased oil
production (19%), lower natural gas prices (7%) and lower oil prices (18%).
Interest and other income increased from $0.02 million in the first
quarter of 1998 to $0.2 million in the first quarter of 1999 due to higher
average cash balances in the current period.
Production expenses for the first quarter of 1999 increased 8% to $5.3
million from $4.9 million in the same period last year, primarily due to higher
workover expenses on Gulf of Mexico properties partially offset by lower current
period severance and ad valorem taxes. Lifting costs (production expenses less
severance and ad valorem taxes) per Mmcfe for the first quarter of 1999
increased 74% compared to the first quarter of 1998, primarily due to the higher
workover expenses and a decrease in production volumes.
Exploration expenses totaled $1.4 million in the first quarter of 1999
and $2.1 million in the corresponding period of 1998, a decrease of 33%, due to
lower dry hole and seismic expenses of $0.7 million and $0.3 million,
respectively, partially offset by higher lease rental expenses.
General and administrative ("G&A") expenses of $1.4 million in the
first quarter of 1999 decreased 26% compared to $1.9 million in the
corresponding period last year. On a unit basis, G&A expenses of $0.18 per Mcfe
were level with the corresponding period in 1998 reflecting the lower G&A
expenses offset by a decline in production volumes.
37
<PAGE> 39
Interest and other debt expenses of $8.7 million in the first quarter
of 1999 increased 7% from $8.1 million in the same period of 1998. The increase
in interest expense resulted primarily from higher average debt levels during
the current period. In addition to its 1999 interest expense of $7.4 million,
the Company recorded non-cash charges in the first quarter of 1999 of $0.5
million for amortization of debt issuance costs, $0.3 million for accretion of
note discount and $0.5 million for accretion of debt valuation discount.
Depreciation, depletion and amortization ("DD&A") expense decreased 8%
from $10.9 million in the first quarter of 1998 to $10.0 million in the current
period, primarily as a result of lower first quarter 1999 production partially
offset by an increase in the units-of-production DD&A rate for oil and gas
activities from $1.00 per Mcfe in the first quarter 1998 to $1.20 per Mcfe in
the current period. This increase in rate was primarily a result of negative
reserve revisions at year end 1998.
The Company recognized a net loss of $11 million in the first quarter
of 1999 and a net loss of $4.8 million in the same period last year. The reasons
for the decline in earnings are described in the foregoing discussion.
The results of operations for the quarter ended March 31, 1999 are not
necessarily indicative of results to be expected for the full year.
Years Ended December 31, 1998 and 1997. The Company's oil and gas
revenues of $79.2 million for 1998 increased 4% compared to $75.9 million in
1997 primarily as a result of an increase in gas production 18%, partially
offset by lower oil prices (32%) and gas prices (8%). The increase in gas
production is primarily due to the Company's SPR acquisition and drilling
activities in north Louisiana.
Interest and other income increased from $0.3 million in 1997 to $0.5
million in 1998 primarily due to business interruption insurance proceeds
related to hurricane disruptions on offshore properties.
Production expenses for 1998 increased 81% to $19.9 million from $11.0
million in the prior year, resulting primarily from the SPR properties acquired
during the fourth quarter of 1997 and higher current period workover expenses.
Higher-cost production from the Gulf of Mexico properties acquired in the SPR
acquisition contributed to a 78% increase in lifting costs (production expenses
less ad valorem and severance taxes) per Mcfe to $0.41 in 1998 as compared to
$0.23 in 1997.
Exploration expenses increased 122% from $5.4 million in 1997 to $12.0
million in 1998 due to increased dry hole, seismic and unproved property
abandonment expenses and higher overhead allocated to exploration activities.
General and administrative expenses of $7.1 million in 1998 increased
3% compared to $6.9 million last year. On a unit of production basis, general
and administrative expenses were $0.19 per Mcfe in 1998 compared to $0.22 per
Mcfe in 1997.
Interest and other debt expenses of $33.3 million in 1998 increased 33%
from $25.1 million in 1997. The increase in interest expense resulted primarily
from higher average debt levels during the current period due to increased
borrowings under the Credit Facility and issuance of the Series C Notes. In
addition to its 1998 interest expense of $28.1 million, the Company recorded
non-cash charges in 1998 of $2.2 million for amortization of debt issuance
costs, $1.0 million for accretion of note discount and $2.0 million for
accretion of debt valuation discount.
Depreciation, depletion and amortization ("DD&A") expense increased 49%
from $25.9 million in 1997 to $38.6 million in 1998, as a result of higher 1998
production levels and an increase in the units-of-production DD&A rate for oil
and gas activities from $0.80 per Mcfe in 1997 to $1.01 in 1998.
In 1998, under Statement of Financial Accounting Standards No. 121
("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of", the Company recognized noncash impairment
charges of $25.7 million against the carrying values of its proved and unproved
oil and gas
38
<PAGE> 40
properties, aggregating $21.6 million and $4.1 million, respectively, for the
year ended December 31, 1998 (see "Property Impairment under SFAS No. 121" in
the "Notes to Consolidated Financial Statements").
The Company recognized a net loss of $(57.0) million in 1998 and net
income of $2.0 million in the prior year. The reasons for the earnings changes
are described in the foregoing discussion.
Years Ended December 31, 1997 and 1996. The Company's oil and gas
revenues of $75.9 million for 1997 increased 25% compared to $60.9 million in
1996 primarily as a result of an increase in gas production (29%), partially
offset by lower oil prices (13%) and gas prices (1%). The increase in gas
production is primarily due to the Company's drilling activities in north
Louisiana and the addition of one month of production from the SPR properties
partially offset by the sale of one-half of its interest in 23 wells and related
facilities in the Houma Embayment in Terrebonne Parish, Louisiana in the fourth
quarter of 1996.
Interest and other income decreased 79% from $1.4 million in 1996 to
$0.3 million in 1997 primarily due to higher 1996 interest income resulting from
invested funds received from the sale of common stock in February 1996 and gains
on the sale of assets recognized in 1996.
Production expenses for 1997 increased 3% to $11.0 million from $10.7
million in the prior year, primarily reflecting higher overall production
levels. On a unit basis, lifting costs (production expenses less ad valorem and
severance taxes) decreased to $0.23 per Mcfe in 1997 compared to $0.31 per Mcfe
in 1996, primarily reflecting lower average costs on north Louisiana production,
which is increasing in proportion to other higher cost production.
Exploration expenses remained constant from 1996 to 1997 at $5.4
million. Increased dry hole expenses were offset by a reduction in lease rental
expense reflecting the joint exploration agreement effective December 1996 in
south Louisiana with Williams.
General and administrative expenses of $6.9 million in 1997 decreased
23% compared to $9.0 million in 1996, reflecting efficiencies obtained in the
realignment of the workforce. This decrease is somewhat offset by a reduction in
1997 in the level of general and administrative expenses either being
capitalized or allocated to exploration expense. On a unit basis, general and
administrative expenses were $0.22 per Mcfe in 1997 compared to $0.36 per Mcfe
in 1996.
Interest and other debt expenses of $25.1 million in 1997 increased 3%
from $24.4 million in 1996. The increase in interest expense resulted primarily
from higher average debt levels during the current period and the payment of
interest associated with the settlement of a lawsuit. These were partially
offset by lower interest rates under the 10 3/8% Senior Subordinated Notes than
under the 13 1/2% Senior Notes retired in October 1996, and lower debt
amortization expenses as a result of the refinancing of the 13 1/2% Senior Notes
and the bank credit facility. See "Liquidity and Capital Resources." In addition
to its 1997 interest expense of $20.9 million, the Company recorded non-cash
charges in 1997 of $1.3 million for amortization of debt issuance costs, $0.9
million for accretion of note discount and $2.0 million for accretion of debt
valuation discount.
Restructuring expense in 1996 was $4.3 million. There was no
restructuring expense in 1997.
Depreciation, depletion and amortization ("DD&A") expense increased 27%
from $20.4 million in 1996 to $25.9 million in 1997, primarily as a result of
higher 1997 production levels. The units-of-production DD&A rate for oil and gas
activities was $0.80 per Mcfe in both 1996 and 1997.
The Company recognized net income of $2.0 million in 1997 and a net
loss before extraordinary item of $(11.9) million in the prior year. The reasons
for the earnings improvement are described in the foregoing discussion.
39
<PAGE> 41
LIQUIDITY AND CAPITAL RESOURCES
During 1998 and through the first quarter of 1999, the oil and gas
industry experienced a worldwide excess of supply over demand for oil and
natural gas resulting in sharply reduced prices. As a result, many companies in
the oil and gas industry, including Kelley Oil & Gas Corporation ("the
Company"), experienced reduced profitability and cash flows which, in turn,
created significant liquidity problems. To address these liquidity issues, the
Company has taken the measures discussed in the following paragraphs.
In April 1999, the Company entered into an Exploration and Development
Agreement with Phillips Petroleum Company ("Phillips") relating to certain of
the Company's interests in the Bryceland, West Bryceland and Sailes fields in
north Louisiana. Pursuant to the agreement, the Company (1) received an $83
million cash payment (subject to certain post-closing adjustments), (2) retained
a 42 Bcf, 8-year volumetric overriding royalty interest and a 1% override on the
excess of production above such royalty interest and (3) retained 25% of its
working interest in the Cotton Valley formation. In addition, Phillips, will at
its risk and expense, operate, develop, exploit and explore the properties
thereby relieving the Company of significant operating, exploration and
development costs in the future. The effective date of the transaction was May
1, 1999 and it closed on May 17, 1999. The Company anticipates recognition of a
gain ranging from approximately $24 million to $28 million in the second quarter
of 1999. The Company has not completed its analysis of the specific costs of the
oil and gas properties and related accumulated depreciation, depletion and
amortization being sold, and accordingly, the gain is subject to further
adjustment.
In April 1999, the Company negotiated a private offering of $135
million principal amount, 14% Senior Secured Notes (the "Notes"). The Notes are
secured by a first lien on substantially all of the Company's proved oil and
natural gas properties remaining after the sale to Phillips and guaranteed by
three entities wholly-owned by the Company. With the consummation of the
Phillips transaction, the Company is obligated to offer to repurchase $35
million principal amount of the Notes at a repurchase price equal to 104% of the
principal amount, plus accrued and unpaid interest to the date of the repurchase
within 30 days of such closing.
In April 1999, the Company began an offer to purchase ("Offer to
Purchase") the outstanding principal amounts of its 7 7/8% Convertible
Subordinated Notes due December 15, 1999 and its 8 1/2% Convertible Subordinated
Debentures due April 1, 2000 (collectively, the "Securities") at a price equal
to $590 per $1,000 principal amount. On May 17, 1999, the Company funded the
repurchase of $46.1 million of the Securities through the Offer to Purchase and
will recognize an extraordinary gain of approximately $18.9 million in the
second quarter of 1999.
The net proceeds from the combination of these transactions and cash on
hand were used by the Company to repay all borrowings outstanding under its
Credit Facility of $115.5 million plus accrued interest, to fund cash collateral
for a $1.5 million letter of credit, and to fund the repurchase of $46.1 million
of Securities under the Offer to Purchase, all at May 17, 1999. The remaining
net proceeds and cash flow from operations will be used to repurchase up to
$35 million of Notes at 104% of their principal amount and for general corporate
purposes.
While industry conditions cannot be predicted with certainty and are
dependent upon a number of commodity and economic factors which are beyond the
company's control, the Company believes that the cash on hand subsequent to the
consummation of the above transactions and the recent increase in oil and
natural gas prices, if continued, will sustain its operations over the
short-term. However, the Company will continue to have significant debt
outstanding and limited ability to incur further indebtedness, which, combined
with industry conditions beyond its control, may adversely affect its financial
condition, results of operations and cash flows.
Liquidity. Net cash provided by operating activities, before working
capital adjustments, during the first three months of 1999 aggregated $1.6
million. Funds used in investing activities were comprised of capital
expenditures of $5.8 million. As a result of these activities, cash and cash
equivalents decreased from $8.4 million at December 31, 1998 to $6.7 as of March
31, 1999. As of March 31, 1999, the Company had a working capital deficit of
$42.2 million, compared to a working capital deficit of $37.4 million at the end
of 1998.
40
<PAGE> 42
Capital Resources. At March 31, 1999, $111.5 million of borrowings and
$1.5 million of letters of credit were outstanding under the Credit Facility. In
April 1999, the Company borrowed an additional $4 million under the Credit
Facility, raising its total outstanding borrowings to $115.5 million as of April
30, 1999. The Company's typical monthly cash flow cycle is such that the Company
usually receives a substantial portion of its proceeds from operations near the
end of each month. Accordingly, outstanding balances under the Credit Facility
may be higher on any given day during the month than at the end of the month.
After the Company paid all amounts outstanding under the Credit
Facility, the Credit Facility was terminated and the Company is not likely to
have access to a revolving credit facility to supplement its cash needs. The
terms of the Notes and subordinated obligations significantly limit the ability
of the Company to incur additional funded indebtedness. Accordingly, the Company
anticipates that it will be required to meet its obligations during the
remainder of 1999 from the net proceeds of the transactions described above,
cash on hand and cash flows from operations. While the Company anticipates that
it will be able to meet its obligations in 1999, there can be no assurance that
it will be able to do so.
The Company had $327.9 million principal amount of debt outstanding as
of March 31, 1999 ($321 million recorded on the balance sheet), requiring $29.8
million in annual cash interest payments. The Company's outstanding $2.625
Convertible Exchangeable Preferred Stock (the "Preferred Stock") is cumulative,
requiring dividends to accumulate, currently at the rate of $4.6 million
annually, and carries liquidation preferences over the Common Stock totaling
$49.8 million at March 31, 1999, including dividend arrearages. The Company has
not declared the quarterly dividend of $0.65625 per preferred share for February
1, 1998, May 1, 1998, August 1, 1998, November 1, 1998, February 1, 1999 and May
1, 1999, aggregating approximately $6.8 million, covering six quarters. Further
dividends are restricted under the Company's indentures governing its 10 3/8%
Senior Subordinated Notes and its 14% Senior Secured Notes. If the Company does
not pay dividends on the Preferred Stock for a period of six quarters, whether
or not consecutive, the holders of the Preferred Stock, as a group, have the
right to elect two additional directors to the Company's Board of Directors.
Capital Commitments. The Company's 1999 capital expenditure budget
provides for $10 million to be expended on development drilling primarily in
north and south Louisiana and $5 million to be expended on exploratory prospects
primarily in south Louisiana, the shallow waters of the Gulf of Mexico, Texas
and New Mexico. In the first three months of 1999, the Company participated in
drilling 2 gross (.5 net) wells, both of which wells were completed in the first
quarter of 1999. As of the end of the first quarter of 1999, the Company was
participating in the drilling of 3 gross (.7 net) wells.
Year 2000. The Company has instigated reviews and evaluations in
response to Year 2000 issues. These issues involve the potential disruption to
systems, processes, and business practices that may occur if system hardware and
software utilized by the Company, its vendors, and customers are unable to
process year 2000 data. The planning phase is completed and the Company is
nearing completion of internal corrective measures.
The Company is working closely with its information systems and
technology vendors to install updated software, where appropriate, that will be
Year 2000 compliant. Currently, more than 90% of the critical Year 2000 internal
systems issues have been tested and corrected. The remainder are expected to be
installed and tested by the end of the third quarter of 1999.
The Company has identified those vendors and others that it believes
provide material services or are vital to its business. Discussions with these
companies to determine their Year 2000 readiness are expected to be completed in
the second quarter 1999. By mid-year 1999 the Company plans to have completed
its Year 2000 review and implemented necessary corrective measures.
The cost of reviewing and implementing corrective measures for Year
2000 issues to date has not been material to the Company and has been limited to
use of Company and vendor personnel for review and implementation of corrective
measures. The Company expects the remainder of the Year 2000 review and
corrective measures to not involve significant costs.
Based on assessments to date and compliance plans in progress, nothing
has come to the attention of management to cause it to believe that Year 2000
issues, including the cost of implementing corrective measures,
41
<PAGE> 43
will have an adverse material impact on the business or operations of the
Company. Nevertheless, as indicated above, achieving Year 2000 readiness is
subject to risk and uncertainties, especially regarding third parties, and there
can be no assurance the Company will not be adversely affected by Year 2000
issues.
The foregoing statements are intended to be and are hereby designated
"Year 2000 Readiness Disclosures" within the meaning of the Year 2000
Information and Readiness Act.
Inflation and Changing Prices. Oil and natural gas prices, as with most
commodities, are highly volatile, have fluctuated during recent years and
generally have not followed the same pattern as inflation.
42
<PAGE> 44
SECTION C. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company is exposed to market risk from changes in interest rates
and commodity prices. The Company has used its Credit Facility and uses its
Senior and Subordinated debt instruments to finance a significant portion of its
operations (see Note 1). The Company's exposure to market risk for interest rate
changes related to its Credit Facility variable rate debt (see Note 1). In the
normal course of business the Company enters into hedging transactions,
including natural gas price and basis swap agreements, to mitigate its exposure
to commodity price movements, but not for trading or speculative purposes. In
the first three months of 1999, the Company used price and basis swap agreements
to reduce exposure to downward price fluctuations for its natural gas
production. For debt obligations the table below presents principal cash flows
and weighted average interest rates by year of maturity. For natural gas price
and basis swap agreements, the table presents notional amounts in Mmbtu's and
weighted average prices for contracts in place at March 31, 1999. The
information presented below should be read in conjunction with Note 4 and Note
10 to the Consolidated Financial Statements (amounts in thousands otherwise
indicated).
<TABLE>
<CAPTION>
MATURITY DATE
------------------------------------------------------------- FAIR VALUE
1999 2000 2001 2002 2003 THEREAFTER TOTAL @ 3/31/99
----------- ----------- --------- --------- -------- ---------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Variable Debt:
Credit Facility
(Maturity) 6.78%(1)........... $ 111,500 $ 111,500 $ 111,500
Fixed Debt:
13.50% (Maturity)............. $ 435 435 435
7.88% (Maturity).............. 34,147 34,147 20,147
8.50% (Maturity).............. 26,856 26,856 15,845
10.38% (Maturity)............. $ 155,000 155,000 97,650
----------- ----------- ---------- ----------- ---------
Total Maturity................... $ 34,582 $ 138,356 $ 155,000 $ 327,938 $ 245,577
=========== =========== ========== =========== =========
Blended weighted
average interest rate......... 7.95% 8.5% 10.38%
Commodity price
derivatives:
Price swaps:
Notional amounts
(Mmbtu's) ................ 5,630,000
Weighted average price........ $ 2.03
Fair value at 3/31/99(2)...... $ (1,050)
Basis swaps:
Notional amounts
(Mmbtu's) ................ 10,980,000
Margin differential(3)........ $ (.03)
Fair value at 3/31/99(2)...... $ (335)
</TABLE>
(1) Reflects the weighted average interest rate on borrowings outstanding at
March 31, 1999.
(2) Represents estimated amounts to settle the contracts at March 31, 1999.
(3) Estimated weighted average margin differential at March 31, 1999.
43
<PAGE> 45
FORWARD-LOOKING STATEMENTS
Statements contained in this Report and other materials filed or to be
filed by the Company with the Securities and Exchange Commission (as well as
information included in oral or other written statements made or to be made by
the Company or its representatives) that are forward-looking in nature are
intended to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended, relating to matters such as anticipated
operating and financial performance, business prospects, developments and
results of the Company. Actual performance, prospects, developments and results
may differ materially from any or all anticipated results due to economic
conditions and other risks, uncertainties and circumstances partly or totally
outside the control of the Company, including rates of inflation, oil and
natural gas prices, uncertainty of reserve estimates, rates and timing of future
production of oil and gas, exploratory and development activities, acquisition
risks, changes in the level and timing of future costs and expenses related to
drilling and operating activities and those risk factors described on pages 13,
14 and 15 of the Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1998.
Words such as "anticipates," "believes," "expects," "estimates,"
"projects" and similar expressions are intended to identify forward-looking
statements. Forward-looking statements include the risk factors described in the
Company's Form 10-K mentioned above.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
EXHIBIT
NUMBER: EXHIBIT
27 Financial Data Schedule (included only in the
electronic filing of this document).
(b) Reports on Form 8-K:
No reports on Form 8-K were filed by the Registrant during the
first quarter of 1999.
44
<PAGE> 46
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
KELLEY OIL & GAS CORPORATION
Date: May 18, 1999 By: /s/ Rick G. Lester
----------------------------------
Rick G. Lester
Chief Financial Officer
(Duly Authorized Officer)
(Principal Accounting Officer)
45
<PAGE> 47
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION
------- -----------
<S> <C>
27 Financial Data Schedule (included only in the elcetronic
filing of this document).
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<CASH> 6,710
<SECURITIES> 0
<RECEIVABLES> 18,499
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 25,977
<PP&E> 544,584
<DEPRECIATION> 293,620
<TOTAL-ASSETS> 278,239
<CURRENT-LIABILITIES> 68,205
<BONDS> 287,959
0
2,600
<COMMON> 1,260
<OTHER-SE> (81,785)
<TOTAL-LIABILITY-AND-EQUITY> 278,239
<SALES> 15,507
<TOTAL-REVENUES> 15,668
<CGS> 0
<TOTAL-COSTS> 6,654
<OTHER-EXPENSES> 11,334
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 8,666
<INCOME-PRETAX> (10,986)
<INCOME-TAX> 0
<INCOME-CONTINUING> (10,986)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (10,986)
<EPS-PRIMARY> (0.10)
<EPS-DILUTED> (0.10)
</TABLE>
