1
EXHIBIT 99.1
OCEAN ENERGY, INC.
SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
AND MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 1997, 1996, 1995, 1994 AND 1993
TABLE OF CONTENTS
Page
----
Report of Independent Public Accountants....................................................................................1
Supplemental Consolidated Financial Statements:
Supplemental Consolidated Statement of Income....................................................................2
Supplemental Consolidated Balance Sheet..........................................................................3
Supplemental Consolidated Statement of Changes in Stockholders' Equity...........................................5
Supplemental Consolidated Statement of Cash Flows................................................................6
Notes to Supplemental Consolidated Financial Statements..........................................................7
Management's Discussion and Analysis of Financial Condition and Results of Operations......................................44
2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
The Board of Directors and Stockholders of
Ocean Energy, Inc. and subsidiaries:
We have previously audited the consolidated balance sheet of Ocean Energy,
Inc. (Ocean) (a Delaware corporation) and subsidiaries as of December 31, 1997,
1996, 1995, 1994 and 1993 and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the years then ended. We have
also previously audited the consolidated balance sheet of United Meridian
Corporation (UMC) (a Delaware corporation) and subsidiaries as of December 31,
1997, 1996, 1995, 1994 and 1993 and the related consolidated statements of
income, changes in stockholders' equity and cash flows for each of the years
then ended. Our most recent reports on Ocean's and UMC's 1997 financial
statements, dated February 16 and 9, 1998, respectively, expressed unqualified
opinions and are included in the companies' Forms 10-K for the year ended
December 31, 1997.
We have also audited the accompanying supplemental consolidated balance
sheet of Ocean Energy, Inc. (a Delaware corporation) and subsidiaries as of
December 31, 1997, 1996, 1995, 1994 and 1993, and the related supplemental
consolidated statements of income, changes in stockholders' equity and cash
flows for each of the years then ended. These supplemental consolidated
financial statements give retroactive effect to the merger of Ocean Energy, Inc.
and United Meridian Corporation on March 27, 1998, which has been accounted for
using the pooling of interests method as described in Note 1. These supplemental
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these supplemental financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the supplemental financial statements referred to above
present fairly, in all material respects, the financial position of Ocean
Energy, Inc. and subsidiaries as of December 31, 1997, 1996, 1995, 1994 and
1993, and the results of their operations and their cash flows for each of the
years then ended, after giving retroactive effect to the merger with United
Meridian Corporation, as described in Note 1, all in conformity with generally
accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
April 6, 1998
1
3
OCEAN ENERGY, INC.
SUPPLEMENTAL CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31,
------------------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
Operating revenues:
Gas sales ................................................... $ 214,100 $ 161,369 $ 91,018 $ 80,843 $ 67,263
Oil sales ................................................... 335,094 233,611 150,303 88,989 60,553
Contract settlements and other .............................. 3,000 854 2,506 2,704 914
--------- --------- --------- --------- ---------
552,194 395,834 243,827 172,536 128,730
--------- --------- --------- --------- ---------
Costs and expenses:
Production costs ............................................ 124,394 98,396 82,937 67,262 49,740
General and administrative .................................. 30,218 27,366 21,070 22,469 11,783
Depreciation, depletion and amortization .................... 248,423 147,643 101,116 91,603 51,184
Impairment of proved oil and gas properties ................. -- -- -- 150,834 --
--------- --------- --------- --------- ---------
403,035 273,405 205,123 332,168 112,707
--------- --------- --------- --------- ---------
Income (loss) from operations .................................. 149,159 122,429 38,704 (159,632) 16,023
Other income, expenses and deductions:
Interest and other income (expense) ......................... 3,187 (449) 677 (16,074) 2,274
Interest and debt expense ................................... (49,134) (40,765) (35,565) (13,547) (7,587)
--------- --------- --------- --------- ---------
Income (loss) before income taxes .............................. 103,212 81,215 3,816 (189,253) 10,710
Income tax benefit (provision):
Current ..................................................... (6,220) (785) (332) (25) (1,131)
Deferred .................................................... (34,772) (25,430) 2,068 67,101 1,943
--------- --------- --------- --------- ---------
Net income (loss) before extraordinary item,
net of income taxes ......................................... 62,220 55,000 5,552 (122,177) 11,522
Extraordinary item, net of income taxes ........................ (19,301) -- -- -- --
--------- --------- --------- --------- ---------
Net income (loss) .............................................. 42,919 55,000 5,552 (122,177) 11,522
Preferred stock dividends ...................................... -- (1,531) (1,484) -- (1,498)
--------- --------- --------- --------- ---------
Net income (loss) available to common stockholders ............. $ 42,919 $ 53,469 $ 4,068 $(122,177) $ 10,024
========= ========= ========= ========= =========
Basic earnings per share before extraordinary item,
net of income taxes ......................................... $ 0.67 $ 0.65 $ 0.06 $ (2.20) $ 0.23
Extraordinary item, net of income taxes ........................ (0.21) -- -- -- --
--------- --------- --------- --------- ---------
Basic earnings per share ....................................... $ 0.46 $ 0.65 $ 0.06 $ (2.20) $ 0.23
========= ========= ========= ========= =========
Weighted average number of common
shares outstanding ......................................... 93,315 82,684 71,515 55,483 44,020
========= ========= ========= ========= =========
Diluted earnings per share before extraordinary item,
net of income taxes ......................................... $ 0.64 $ 0.62 $ 0.06 $ (2.20) $ 0.22
Extraordinary item, net of income taxes ........................ (0.20) -- -- -- --
--------- --------- --------- --------- ---------
Diluted earnings per share ..................................... $ 0.44 $ 0.62 $ 0.06 $ (2.20) $ 0.22
========= ========= ========= ========= =========
Weighted average number of common shares and
common share equivalents outstanding ........................ 96,646 85,905 73,405 55,483 44,775
========= ========= ========= ========= =========
The accompanying notes are an integral part of these supplemental
consolidated financial statements.
2
4
OCEAN ENERGY, INC.
SUPPLEMENTAL CONSOLIDATED BALANCE SHEET
(IN THOUSANDS)
DECEMBER 31,
-----------------------------------------------------------------
1997 1996 1995 1994 1993
----------- ----------- ----------- ----------- ----------
ASSETS
Current assets:
Cash and cash equivalents ................................. $ 11,689 $ 60,701 $ 13,798 $ 12,393 $ 694
Accounts receivable, net of allowance for doubtful accounts
of $1,190 at December 31, 1997 and 1996 and $1,266
at December 31, 1995, 1994 and 1993:
Oil and gas sales ..................................... 75,642 70,008 35,734 25,634 21,414
Joint interest and other .............................. 49,289 48,949 22,912 16,068 10,105
Shareholders .......................................... -- -- 129 125 276
Deferred income taxes ..................................... 1,547 2,839 3,875 15,498 3,672
Inventory ................................................. 11,097 49,926 15,775 6,726 1,060
Prepaid expenses and other ................................ 10,630 8,934 3,345 4,460 1,443
----------- ----------- ----------- ----------- ----------
159,894 241,357 95,568 80,904 38,664
----------- ----------- ----------- ----------- ----------
Property and equipment, at cost:
Oil and gas (full cost method)
Evaluated properties .................................. 2,043,700 1,380,074 1,087,979 960,289 605,449
Unevaluated properties excluded from amortization ..... 232,726 94,572 31,410 26,134 1,384
Other ..................................................... 28,182 15,355 9,830 5,358 4,380
----------- ----------- ----------- ----------- ----------
2,304,608 1,490,001 1,129,219 991,781 611,213
Accumulated depreciation, depletion and amortization ...... (880,771) (658,776) (555,143) (482,007) (247,994)
----------- ----------- ----------- ----------- ----------
1,423,837 831,225 574,076 509,774 363,219
----------- ----------- ----------- ----------- ----------
Other assets:
Gas imbalances receivable ................................. 6,227 5,702 5,852 6,678 5,595
Deferred income taxes ..................................... 130 16,885 28,804 14,204 27,091
Deferred financing costs .................................. 19,661 18,913 15,033 10,456 3,977
Restricted deposits ....................................... 8,497 6,323 4,260 2,300 810
Other ..................................................... 24,749 836 867 3,376 2,628
----------- ----------- ----------- ----------- ----------
59,264 48,659 54,816 37,014 40,101
----------- ----------- ----------- ----------- ----------
TOTAL ASSETS ....................................... $ 1,642,995 $ 1,121,241 $ 724,460 $ 627,692 $ 441,984
=========== =========== =========== =========== ==========
The accompanying notes are an integral part of these supplemental
consolidated financial statements.
3
5
OCEAN ENERGY, INC.
SUPPLEMENTAL CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT FOR SHARE AMOUNTS)
DECEMBER 31,
-------------------------------------------------------------------
1997 1996 1995 1994 1993
----------- ----------- ----------- ----------- -----------
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ........................................ $ 188,429 $ 131,807 $ 77,188 $ 66,652 $ 42,302
Advances from joint owners .............................. 8,491 5,845 8,456 2,149 314
Interest payable ........................................ 16,476 9,321 6,261 2,421 400
Accrued liabilities ..................................... 6,572 15,310 7,201 9,253 3,587
Notes payable ........................................... -- -- 10,639 -- --
Current maturities of long-term debt .................... 911 1,026 3,984 -- --
----------- ----------- ----------- ----------- -----------
220,879 163,309 113,729 80,475 46,603
----------- ----------- ----------- ----------- -----------
Long-term debt ............................................. 672,298 440,974 416,491 393,673 105,597
----------- ----------- ----------- ----------- -----------
Deferred credits and other liabilities:
Deferred income taxes ................................... 11,159 13,450 10,014 8,819 18,749
Gas imbalances payable .................................. 5,861 3,994 6,377 7,113 6,358
Deferred oil and gas revenue ............................ -- -- -- -- 108,784
Other ................................................... 7,461 6,442 6,523 10,984 2,550
----------- ----------- ----------- ----------- -----------
24,481 23,886 22,914 26,916 136,441
----------- ----------- ----------- ----------- -----------
Stockholders' equity:
Preferred stock, $0.01 par value, 10,000,000 shares
authorized, no shares issued and outstanding
at December 31, 1997, 1996, 1995, 1994 and 1993 ..... -- -- -- -- --
Series F preferred stock, $0.01 par value, 1,166,667
shares authorized, issued and outstanding at
December 31, 1995, no shares issued and outstanding
at December 1997, 1996, 1994 and 1993 ............... -- -- 12 -- --
Common stock, $0.01 par value, 250,000,000 shares
authorized, 100,109,241, 91,741,503,
71,798,544, 71,138,445 and 67,936,131
shares issued and outstanding at December 31, 1997,
1996, 1995, 1994 and 1993, respectively ............. 1,001 918 718 711 294
Additional paid-in capital .............................. 823,956 632,111 363,822 323,153 231,305
Foreign currency translation adjustment ................. (6,839) (4,257) (4,057) (3,999) (1,907)
Retained earnings (deficit) ............................. (92,781) (135,700) (189,169) (193,237) (76,349)
----------- ----------- ----------- ----------- -----------
725,337 493,072 171,326 126,628 153,343
----------- ----------- ----------- ----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .............. $ 1,642,995 $ 1,121,241 $ 724,460 $ 627,692 $ 441,984
=========== =========== =========== =========== ===========
The accompanying notes are an integral part of these
supplemental consolidated financial statements.
4
6
OCEAN ENERGY, INC.
SUPPLEMENTAL CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996, 1995, 1994 AND 1993
SERIES A-F
PREFERRED STOCK COMMON STOCK
------------------------- -----------------------
SHARES AMOUNT SHARES AMOUNT
---------- ----------- ---------- ---------
Balance, December 31, 1992 ......................................... 20,688,463 $ 207 26,669,049 $ 75
Preferred stock issuance, Series E
- April 30 ...................................................... 1,400,000 14 -- --
- June 11 ....................................................... 313,962 3 -- --
Adjustment resulting from recording the acquisition of Norfolk
Holdings, Inc. in accordance with the purchase method ......... -- -- -- --
Adjustment to reflect 1 for 2 reverse stock split ................ -- -- (3,682,024) (37)
Foreign currency translation adjustment .......................... -- -- -- --
Preferred stock dividends ........................................ -- -- -- --
UMC initial public stock offering, July 22 ....................... -- -- 5,720,000 57
Conversion of preferred stock to common stock, July 22 ........... (22,402,425) (224) 19,924,106 199
Issuance of common stock ......................................... -- -- 19,305,000 --
Distributions .................................................... -- -- -- --
Net income ....................................................... -- -- -- --
---------------------------------------------------------
Balance, December 31, 1993 ......................................... -- $ -- 67,936,131 $ 294
OEI sale of stock ................................................ -- -- 15,795,000 158
Repurchase of common stock ....................................... -- -- (19,305,000) --
Adjustment resulting from recording the acquisition of General
Atlantic Resources, Inc. (GARI) in accordance with the
purchase method ............................................... -- -- -- --
Foreign currency translation adjustment .......................... -- -- -- --
Exercise of common stock options ................................. -- -- 187,687 2
Issuance of common stock as partial purchase in GARI merger ...... -- -- 6,524,627 65
Recapitalization of common stock ................................. -- -- -- 192
Distributions .................................................... -- -- -- --
Reclassification of accumulated deficit at date of conversion to
a subchapter C corp ........................................... -- -- -- --
Net loss ......................................................... -- -- -- --
---------------------------------------------------------
Balance, December 31, 1994 ......................................... -- $ -- 71,138,445 $ 711
Foreign currency translation adjustment .......................... -- -- -- --
Preferred stock issuance
- June 30 ..................................................... 833,333 8 -- --
- July 24 ..................................................... 333,334 4 -- --
Exercise of common stock options ................................. -- -- 556,846 6
Preferred stock dividends ........................................ -- -- -- --
Sale of common stock ............................................. -- -- 103,253 1
Net income ....................................................... -- -- -- --
---------------------------------------------------------
Balance, December 31, 1995 ......................................... 1,166,667 $ 12 71,798,544 $ 718
OEI common stock offering ........................................ -- -- 10,530,000 106
Foreign currency translation adjustment .......................... -- -- -- --
Automatic conversion of Series F preferred stock to
common stock .................................................. (1,166,667) (12) 2,398,869 24
UMC common stock offering ........................................ -- -- 5,315,625 53
Exercise of common stock options ................................. -- -- 1,391,991 14
Exercise of warrants ............................................. -- -- 306,474 3
Preferred stock dividends ........................................ -- -- -- --
Net income ....................................................... -- -- -- --
---------------------------------------------------------
Balance, December 31, 1996 ......................................... -- $ -- 91,741,503 $ 918
Foreign currency translation adjustment .......................... -- -- -- --
OEI common stock offering ........................................ -- -- 7,254,000 73
Common shares issued in exchange for shares tendered from
a prior acquisition ........................................... -- -- 3,461 --
Exercise of common stock options ................................. -- -- 1,110,277 10
Net income ....................................................... -- -- -- --
---------------------------------------------------------
Balance, December 31, 1997 ......................................... -- $ -- 100,109,241 $ 1,001
=========================================================
ADDITIONAL FOREIGN RETAINED
PAID-IN CURRENCY EARNINGS
CAPITAL ADJUSTMENT (DEFICIT) TOTAL
---------- ---------- --------- --------
Balance, December 31, 1992 ......................................... $ 118,439 -- $ (82,972) $ 35,749
Preferred stock issuance, Series E
- April 30 ...................................................... 34,441 -- -- 34,455
- June 11 ....................................................... 7,846 -- -- 7,849
Adjustment resulting from recording the acquisition of Norfolk
Holdings, Inc. in accordance with the purchase method ......... 1,893 -- -- 1,893
Adjustment to reflect 1 for 2 reverse stock split ................ 37 -- -- --
Foreign currency translation adjustment .......................... -- (1,907) -- (1,907)
Preferred stock dividends ........................................ -- -- (1,498) (1,498)
UMC initial public stock offering, July 22 ....................... 68,624 -- -- 68,681
Conversion of preferred stock to common stock, July 22 ........... 25 -- -- --
Issuance of common stock ......................................... -- -- -- --
Distributions .................................................... -- -- (3,401) (3,401)
Net income ....................................................... -- -- 11,522 11,522
---------------------------------------------------------
Balance, December 31, 1993 ......................................... $ 231,305 $ (1,907) $ (76,349) $ 153,343
OEI sale of stock ................................................ 52,649 -- -- 52,807
Repurchase of common stock ....................................... (18,700) -- -- (18,700)
Adjustment resulting from recording the acquisition of General
Atlantic Resources, Inc. (GARI) in accordance with the
purchase method ............................................... (82) -- -- (82)
Foreign currency translation adjustment .......................... -- (2,092) -- (2,092)
Exercise of common stock options ................................. 1,403 -- -- 1,405
Issuance of common stock as partial purchase in GARI merger ...... 63,459 -- -- 63,524
Recapitalization of common stock ................................. (192) -- -- --
Distributions .................................................... -- -- (1,400) (1,400)
Reclassification of accumulated deficit at date of conversion to
a subchapter C corp ........................................... (6,689) -- 6,689 --
Net loss ......................................................... -- -- (122,177) (122,177)
---------------------------------------------------------
Balance, December 31, 1994 ......................................... $ 323,153 $ (3,999) $ (193,237) $ 126,628
Foreign currency translation adjustment .......................... -- (58) -- (58)
Preferred stock issuance
- June 30 ..................................................... 24,992 -- -- 25,000
- July 24 ..................................................... 9,902 -- -- 9,906
Exercise of common stock options ................................. 5,405 -- -- 5,411
Preferred stock dividends ........................................ -- -- (1,484) (1,484)
Sale of common stock ............................................. 370 -- -- 371
Net income ....................................................... -- -- 5,552 5,552
Balance, December 31, 1995 ......................................... $ 363,822 $ (4,057) $ (189,169) $ 171,326
OEI common stock offering ........................................ 62,086 -- -- 62,192
Foreign currency translation adjustment .......................... -- (200) -- (200)
Automatic conversion of Series F preferred stock to
common stock .................................................. (12) -- -- --
UMC common stock offering ........................................ 182,617 -- -- 182,670
Exercise of common stock options ................................. 19,980 -- -- 19,994
Exercise of warrants ............................................. 3,618 -- -- 3,621
Preferred stock dividends ........................................ -- -- (1,531) (1,531)
Net income ....................................................... -- -- 55,000 55,000
---------------------------------------------------------
Balance, December 31, 1996 ......................................... $ 632,111 $ (4,257) $ (135,700) $ 493,072
Foreign currency translation adjustment .......................... -- (2,582) -- (2,582)
OEI common stock offering ........................................ 177,674 -- -- 177,747
Common shares issued in exchange for shares tendered from
a prior acquisition ........................................... -- -- -- --
Exercise of common stock options ................................. 14,171 -- -- 14,181
Net income ....................................................... -- -- 42,919 42,919
---------------------------------------------------------
Balance, December 31, 1997 ......................................... $ 823,956 $ (6,839) $ (92,781) $ 725,337
=========================================================
The accompanying notes are an integral part of these
supplemental consolidated financial statements.
5
7
SUPPLEMENTAL CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
YEARS ENDED DECEMBER 31,
---------------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
Cash flows from operating activities:
Net income (loss) ............................................ $ 42,919 $ 55,000 $ 5,552 $(122,177) $ 11,522
Adjustments to reconcile net income (loss) to cash
provided by (used in) operating activities:
Depreciation, depletion and amortization ................... 248,423 147,643 101,116 91,603 51,184
Impairment of proved oil and gas properties ................ -- -- -- 150,834 5,368
Amortization of debt issue cost ............................ 2,957 2,891 1,783 581 893
Recognition of deferred revenue on sale of
production payment ....................................... -- -- -- (23,857) (18,294)
Repurchase of production payment interests ................. -- -- -- (107,952) --
Prepayment of production payment interests ................. -- -- -- -- (947)
Sale of production payment interests ....................... -- -- -- -- 95,678
Deferred hedge revenue ..................................... (133) (470) 204 (565) 1,147
Deferred income tax provision (benefit) .................... 20,821 24,183 (2,068) (67,101) (7,311)
--------- --------- --------- --------- ---------
314,987 229,247 106,587 (78,634) 139,240
Changes in assets and liabilities:
Increase in receivables .................................. (17,338) (42,074) (16,673) (91) (12,274)
Decrease (increase) in inventory ......................... (1,099) (7,589) 1,590 (5,666) (454)
Increase in payables and accrued liabilities ............. 39,418 35,355 14,145 8,483 21,605
Increase (decrease) in net gas imbalances ................ 1,342 (2,233) 729 (328) (320)
Other .................................................... 2,365 (3,393) (1,065) 4,318 (1,562)
--------- --------- --------- --------- ---------
Net cash provided by (used in) operating activities ... 339,675 209,313 105,313 (71,918) 146,235
--------- --------- --------- --------- ---------
Cash flows from investing activities:
Additions to oil and gas properties .......................... (819,465) (472,021) (233,038) (91,728) (146,785)
Additions to other property and equipment .................... (11,018) (4,074) (3,346) (991) (1,147)
Net proceeds from the sale of assets ......................... 52,855 50,152 78,119 2,376 15,317
(Increase) decrease in restricted deposits ................... (2,173) (2,064) (1,959) (1,221) 288
Increase in other assets ..................................... (23,878) -- -- -- --
Corporate acquisitions (net of cash acquired) ................ -- -- -- (129,182) (141,954)
Purchase of minority interest ................................ -- -- -- (5,977) --
--------- --------- --------- --------- ---------
Net cash used in investing activities ................. (803,679) (428,007) (160,224) (226,723) (274,281)
--------- --------- --------- --------- ---------
Cash flows from financing activities:
Repayment of long-term debt .................................. (594,977) (403,095) (418,391) (145,931) (198,240)
Additions to total debt ...................................... 826,081 419,052 444,298 418,799 222,399
Deferred financing costs ..................................... (3,648) (6,408) (6,248) (6,640) (4,305)
Net proceeds from issuance of preferred stock ................ -- -- 34,906 -- 42,304
Net proceeds from common stock offerings ..................... 178,108 245,178 370 52,807 68,681
Preferred stock dividends .................................... -- (1,531) (1,484) -- (1,498)
Proceeds from common stock options and
warrants exercised ......................................... 9,428 12,401 2,865 1,405 --
Repurchase of common stock ................................... -- -- -- (8,700) --
Distributions to stockholders ................................ -- -- -- (1,400) (2,400)
--------- --------- --------- --------- ---------
Net cash provided by financing activities ............. 414,992 265,597 56,316 310,340 126,941
--------- --------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents ............ (49,012) 46,903 1,405 11,699 (1,105)
Cash and cash equivalents at beginning of period ................ 60,701 13,798 12,393 694 1,799
--------- --------- --------- --------- ---------
Cash and cash equivalents at end of period ...................... $ 11,689 $ 60,701 $ 13,798 $ 12,393 $ 694
========= ========= ========= ========= =========
The accompanying notes are an integral part of these
supplemental consolidated financial statements.
6
8
OCEAN ENERGY, INC.
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 ORGANIZATION
The accompanying supplemental consolidated financial statements of Ocean
Energy, Inc. (OEI or the Company), a Delaware corporation, have been prepared
pursuant to the rules and regulations of the Securities and Exchange Commission
(SEC).
The Company is an independent energy company engaged in the exploration,
development, production and acquisition of natural gas and crude oil offshore
Gulf of Mexico, across North America and in the oil and natural gas producing
regions of Cote d'Ivoire, Equatorial Guinea, Pakistan and Bangladesh.
On March 27, 1998, pursuant to the Agreement and Plan of Merger dated
December 22, 1997, United Meridian Corporation (UMC) was merged into the Company
(the Merger). As a result of the Merger, each outstanding share of UMC common
stock was converted into 1.3 shares of OEI common stock with approximately 46
million shares issued to the shareholders of UMC representing approximately 46%
of all of the issued and outstanding shares of OEI. The Company's shareholders
received 2.34 shares of OEI shares for each share outstanding immediately
preceding the Merger representing approximately 54% of all of the issued and
outstanding shares of OEI. The Merger was accounted for as a pooling of
interests. Accordingly, the accompanying consolidated financial statements for
periods prior to the merger have been restated to combine the historical results
of OEI and UMC. All common share data throughout these financial statements have
been restated to reflect the impact of the respective stock splits resulting
from the Merger.
The following table represents the results of operations of the previously
separate companies before the Merger (in thousands):
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
Revenue:
OEI .................................... $ 292,180 $ 188,451 $ 127,970 $ 75,395 $ 47,483
UMC* ................................... 260,014 207,383 115,857 97,141 81,247
--------- --------- --------- --------- ---------
Revenue, as reported ................... $ 552,194 $ 395,834 $ 243,827 $ 172,536 $ 128,730
========= ========= ========= ========= =========
Net income (loss):
OEI .................................... $ 37,450 $ 20,951 $ 3,598 $ (15,875) $ 2,227
UMC* ................................... 24,770 34,049 1,954 (106,302) 9,295
--------- --------- --------- --------- ---------
Net income, before extraordinary item .. 62,220 55,000 5,552 (122,177) 11,522
Extraordinary item ..................... (19,301) -- -- -- --
--------- --------- --------- --------- ---------
Net income (loss), as reported ......... $ 42,919 $ 55,000 $ 5,552 $(122,177) $ 11,522
========= ========= ========= ========= =========
Stockholders' Equity:
OEI .................................... $ 305,272 $ 105,153 $ 19,976 $ 16,007 $ (825)
UMC* ................................... 420,065 387,919 151,350 110,621 154,168
--------- --------- --------- --------- ---------
$ 725,337 $ 493,072 $ 171,326 $ 126,628 $ 153,343
========= ========= ========= ========= =========
* Amount represents UMC converted to the full cost method of accounting for
its oil and gas producing activities.
Certain adjustments were made to the historical results of UMC and OEI to
conform the accounting policies and presentation used by the companies,
including the conversion of UMC to the full cost method of accounting for its
oil and gas producing activities. The effect of these conforming adjustments
increased (decreased) UMC's net income (loss) by $5.0 million, $16.6 million,
($0.1) million, ($25.3) million and $20.1 million for the years ended December
31, 1997, 1996, 1995, 1994 and 1993.
The supplemental consolidated financial statements reflect all adjustments
that, in the opinion of management, are necessary for a fair presentation.
7
9
NOTE 2 SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The supplemental consolidated financial statements include the accounts of
the Company and its majority-owned affiliates. Interests in joint ventures,
limited liability companies and partnerships are accounted for under the
proportional consolidation method. All significant intercompany balances and
transactions have been eliminated in consolidation.
Certain reclassifications of amounts previously reported have been made to
conform to current year presentation.
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.
INVENTORY
The Company conducts a portion of its oil and gas activities with a small
group of institutional and corporate investors. In connection therewith, the
Company periodically acquires oil and gas properties with the intention of
selling a portion of its interests to such investors or industry partners. To
the extent those properties are to be resold, costs are carried as a current
asset and classified as inventory. No gain or loss is recognized on inventoried
properties. At December 31, 1996, 1995, and 1994, costs of properties to be
resold included in inventory totaled $39.5 million, $12.4 million and $4.5
million, respectively. The corresponding balance at December 31, 1997 was not
significant and no such properties were held at December 31, 1993. The remaining
inventory consists of tubular goods and other equipment.
OIL AND GAS PROPERTIES
The Company's exploration and production activities are accounted for under
the full cost method. Under this method, all acquisition, exploration and
development costs, including certain related employee costs, incurred for the
purpose of finding oil and gas are capitalized. Such amounts include the cost of
drilling and equipping productive wells, dry hole costs, lease acquisition
costs, delay rentals, and costs related to such activities. Employee costs
associated with production operations and general corporate activities are
expensed in the period incurred. Transactions involving sales of reserves in
place, unless unusually significant, are recorded as adjustments to oil and gas
properties. Capitalized costs are limited to the sum of the present value of
future net revenues discounted at 10%, net of expected income taxes, related to
estimated production of proved reserves and the lower of cost or estimated fair
value of unevaluated properties.
Depreciation, depletion and amortization of oil and gas properties is
computed on a country-by-country basis using a unit-of-production method based
on estimated proved reserves. All costs associated with evaluated oil and gas
properties, including an estimate of future development, restoration,
dismantlement and abandonment costs associated therewith, are included in the
computation base. A majority of the oil and gas reserves are estimated
periodically by independent petroleum engineers. The Company evaluates all
unevaluated oil and gas properties on a quarterly basis to determine if any
impairment has occurred or if the property has been otherwise evaluated. If a
property has been evaluated, or if there is determined to be any impairment,
costs related to the particular unevaluated properties are reclassified as an
evaluated oil and gas property, and thus subject to amortization if there are
proved reserves associated with the related cost center. Otherwise, such
impairment will be recognized in the period in which it occurs.
OTHER PROPERTY AND EQUIPMENT
Other property consists primarily of furniture, office equipment, leasehold
improvements and computers. The majority of these assets are depreciated on a
straight-line basis with estimated useful lives ranging from three to seven
years.
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OTHER ASSETS
Included in other assets at December 31, 1997, is $23.9 million of advance
payments for seismic data which will not be received until 1998.
GAS IMBALANCES
The Company converted to the entitlements method of accounting from the
sales method of accounting for gas imbalances. The conversion did not materially
impact the Company's results of operations or financial position on a cumulative
basis or for any of the periods presented. Under the entitlements method, the
Company records as revenue only that portion of gas production sold and
allocable to its ownership interest in the related well. Imbalance payables are
recorded at historical amounts and imbalance receivables are valued at the lower
of (i) the price in effect at the time of production, (ii) the current market
value or (iii) the contract price net of selling expenses. Gas imbalances arise
when a purchaser takes delivery of more or less gas volume from a well than the
Company's actual interest in the production from that well. Such imbalances are
reduced either by subsequent recoupment of over-and-under deliveries or by cash
settlement, as required by applicable contracts. Under-deliveries are included
in Other assets and over-deliveries are included in Deferred credits and other
liabilities.
HEDGING
The Company periodically enters into contracts in order to hedge against
the volatility of oil and gas prices. The Company enters into such transactions
for the purpose of managing the overall impact of commodity price volatility.
These transactions generally take the form of swaps or price collars, and are
placed with major financial institutions. The results of such transactions are
included as Oil or Gas sales in the Supplemental Consolidated Statement of
Income as the related production volumes are sold.
The Company enters into interest rate hedge contracts from time to time
with major financial institutions. These transactions are made to protect
against higher future interest costs on the Company's floating rate long-term
debt. The results of interest rate hedges are included in Interest and debt
expense on the Supplemental Consolidated Statement of Income.
FEDERAL INCOME TAXES
The Company follows the provisions of Statement of Financial Accounting
Standards (SFAS) No. 109, Accounting for Income Taxes, under which deferred tax
assets or liabilities are estimated at the financial statement date based upon
(i) temporary differences between the tax basis of assets and liabilities and
their reported amounts in the financial statements and (ii) net operating loss
and tax credit carryforwards for tax purposes.
EARNINGS PER SHARE
The Company adopted SFAS No. 128, Earnings Per Share, during the fourth
quarter of 1997. In accordance with this new pronouncement, basic earnings per
share is computed by dividing net income (loss) available to common stockholders
by the weighted average number of common shares outstanding during the period.
Diluted earnings per share is determined on the assumption that outstanding
stock options have been converted using the average price for the period. For
purposes of computing earnings per share in a loss year, common stock
equivalents have been excluded from the computation of weighted average common
shares outstanding because their effect is anti-dilutive. Prior period amounts
have been restated in accordance with the requirements of the pronouncement.
STATEMENT OF CASH FLOWS
Cash flows from operating activities for 1997, 1996, 1995, 1994 and 1993,
include cash payments for interest of $49.6 million, $42.9 million, $32.9
million, $10.9 million and $6.7 million and income taxes of $1.8 million, $0.4
million, $0.6 million, $0.4 million, and $0.9 million, respectively.
9
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FOREIGN CURRENCY TRANSLATION
The United States (U.S.) dollar is the functional currency for all
international locations except for Canada, which uses the Canadian dollar. The
financial position and results of operations attributable to the Company's
Canadian operations are translated into U.S. currency in accordance with SFAS
No. 52, Foreign Currency Translation. Accordingly, the assets and liabilities of
the financial statements are translated using the currency exchange rate in
effect at the balance sheet date while the revenues, expenses, gains and losses
are translated using the exchange rate for the periods in which they occurred.
The effect of such translations are reflected as adjustments to stockholders'
equity as shown in the Supplemental Consolidated Statement of Changes in
Stockholders' Equity.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
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NOTE 3 OIL AND GAS PROPERTY COSTS
Capitalized costs at December 31, 1997, 1996, 1995, 1994 and 1993 relating
to the Company's oil and gas activities are shown below (in thousands):
EQUATORIAL
GUINEA
UNITED COTE AND OTHER
STATES CANADA D'IVOIRE FOREIGN TOTAL
--------------- --------------- --------------- --------------- ---------------
AS OF DECEMBER 31, 1997
Proved properties ..................... $ 1,604,809 $ 114,190 $ 109,801 $ 214,900 $ 2,043,700
Unproved oil and gas interests ........ 212,531 48 18,272 1,875 232,726
--------------- --------------- --------------- --------------- ---------------
Total capitalized costs ............... 1,817,340 114,238 128,073 216,775 2,276,426
Less: Accumulated depreciation,
depletion and amortization ........ (731,275) (51,396) (25,984) (59,228) (867,883)
--------------- --------------- --------------- --------------- ---------------
Net capitalized costs ................. $ 1,086,065 $ 62,842 $ 102,089 $ 157,547 $ 1,408,543
=============== =============== =============== =============== ===============
AS OF DECEMBER 31, 1996
Proved properties ..................... $ 1,130,201 $ 94,088 $ 70,193 $ 85,592 $ 1,380,074
Unproved oil and gas interests ........ 92,561 50 1,072 889 94,572
--------------- --------------- --------------- --------------- ---------------
Total capitalized costs ............... 1,222,762 94,138 71,265 86,481 1,474,646
Less: Accumulated depreciation,
depletion and amortization ........ (579,697) (46,615) (11,429) (12,754) (650,495)
--------------- --------------- --------------- --------------- ---------------
Net capitalized costs ................. $ 643,065 $ 47,523 $ 59,836 $ 73,727 $ 824,151
=============== =============== =============== =============== ===============
AS OF DECEMBER 31, 1995
Proved properties ..................... $ 915,322 $ 101,431 $ 54,968 $ 16,258 $ 1,087,979
Unproved oil and gas interests ........ 29,856 50 1,072 432 31,410
--------------- --------------- --------------- --------------- ---------------
Total capitalized costs ............... 945,178 101,481 56,040 16,690 1,119,389
Less: Accumulated depreciation,
depletion and amortization ........ (496,826) (48,253) (2,367) (1,893) (549,339)
--------------- --------------- --------------- --------------- ---------------
Net capitalized costs ................. $ 448,352 $ 53,228 $ 53,673 $ 14,797 $ 570,050
=============== =============== =============== =============== ===============
AS OF DECEMBER 31, 1994
Proved properties ..................... $ 849,612 $ 94,019 $ 13,370 $ 3,288 $ 960,289
Unproved oil and gas interests ........ 24,225 1,469 -- 440 26,134
--------------- --------------- --------------- --------------- ---------------
Total capitalized costs ............... 873,837 95,488 13,370 3,728 986,423
Less: Accumulated depreciation,
depletion and amortization ........ (435,929) (42,855) -- -- (478,784)
--------------- --------------- --------------- --------------- ---------------
Net capitalized costs ................. $ 437,908 $ 52,633 $ 13,370 $ 3,728 $ 507,639
=============== =============== =============== =============== ===============
AS OF DECEMBER 31, 1993
Proved properties ..................... $ 527,783 $ 75,907 $ 1,759 $ -- $ 605,449
Unproved oil and gas interests ........ 623 -- -- 761 1,384
--------------- --------------- --------------- --------------- ---------------
Total capitalized costs ............... 528,406 75,907 1,759 761 606,833
Less: Accumulated depreciation
depletion and amortization ........ (241,723) (4,360) -- -- (246,083)
--------------- --------------- --------------- --------------- ---------------
Net capitalized costs ................. $ 286,683 $ 71,547 $ 1,759 $ 761 $ 360,750
=============== =============== =============== =============== ===============
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Costs incurred during 1997, 1996, 1995, 1994 and 1993 in the Company's oil
and gas activities were as follows (in thousands):
EQUATORIAL
GUINEA
UNITED COTE AND OTHER
STATES CANADA D'IVOIRE FOREIGN TOTAL
----------- ----------- ------------- ----------- -----------
YEAR ENDED DECEMBER 31, 1997
Property acquisition costs:
Proved .............................................. $ 120,520 $ 9,554 $ -- $ -- $ 130,074
Unproved ............................................ 105,394 2,423 -- -- 107,817
Exploration costs ..................................... 139,824 5,811 15,344 89,719 250,698
Development costs ..................................... 248,363 9,308 23,462(1) 36,842 317,975
Capitalized interest on unevaluated properties ........ 12,802 -- -- -- 12,802
Capitalized general and administrative costs .......... 9,037 452 896 4,607 14,992
----------- ----------- ----------- ----------- -----------
Total costs incurred .................................. $ 635,940 $ 27,548 $ 39,702(1) $ 131,168 $ 834,358
=========== =========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 1996
Property acquisition costs:
Proved ............................................. $ 65,658 $ 447 $ -- $ -- $ 66,105
Unproved ........................................... 74,043 865 -- 457 75,365
Properties held for resale ........................... (37,200) (37,200)
Exploration costs .................................... 72,241 1,833 9,253 25,103 108,430
Development costs .................................... 140,420 4,572 9,369 56,707 211,068
Capitalized interest on unevaluated properties ....... 5,299 -- -- 2,109 7,408
Capitalized general and administrative costs ......... 6,360 537 (34) 3,670 10,533
----------- ----------- ----------- ----------- -----------
Total costs incurred ................................. $ 326,821 $ 8,254 $ 18,588 $ 88,046 $ 441,709
=========== =========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 1995
Property acquisition costs:
Proved ............................................. $ 25,443 $ 376 $ -- $ -- $ 25,819
Unproved ........................................... 5,413 311 -- -- 5,724
Exploration costs .................................... 36,380 1,375 1,666 9,571 48,992
Development costs .................................... 79,317 2,519 42,900 19,798 144,534
Capitalized interest on unevaluated properties ....... 3,133 -- 749 -- 3,882
Capitalized general and administrative costs ......... 4,630 224 497 2,377 7,728
----------- ----------- ----------- ----------- -----------
Total costs incurred ................................. $ 154,316 $ 4,805 $ 45,812 $ 31,746 $ 236,679
=========== =========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 1994
Property acquisition costs:
Proved ............................................. $ 25,572 $ 667 $ -- $ -- $ 26,239
Unproved ........................................... 16,702 118 -- -- 16,820
Corporate acquisition cost ........................... 235,914 23,744 -- -- 259,658
Exploration costs .................................... 19,049 2,321 816 1,761 23,947
Development costs .................................... 42,708 5,014 7,598 -- 55,320
Capitalized interest on unevaluated properties ....... 398 48 -- -- 446
Capitalized general and administrative costs ......... 1,466 -- 83 1,761 3,310
----------- ----------- ----------- ----------- -----------
Total costs incurred ................................. $ 341,809 $ 31,912 $ 8,497 $ 3,522 $ 385,740
=========== =========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 1993
Property acquisition costs:
Proved ............................................. $ 116,955 $ -- $ -- $ -- $ 116,955
Unproved ........................................... 853 -- -- -- 853
Corporate acquisition cost ........................... 78,036 72,104 -- -- 150,140
Exploration costs .................................... 5,192 2,035 272 1,167 8,666
Development costs .................................... 27,178 2,478 1,517 -- 31,173
Capitalized interest on unevaluated properties ....... -- -- -- -- --
Capitalized general and administrative costs ......... -- -- 403 798 1,201
----------- ----------- ----------- ----------- -----------
Total costs incurred ................................. $ 228,214 $ 76,617 $ 2,192 $ 1,965 $ 308,988
=========== =========== =========== =========== ===========
(1) Amounts do not include $17,229 incurred on a LPG plant in Cote d'Ivoire.
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Capitalized unevaluated costs related primarily to acquisition, lease and
seismic costs, the majority of which will be evaluated over a five-year period,
were as follows (in thousands):
Balance at Cost Incurred During The Years Ended December 31,
December 31, ----------------------------------------------------------
1997 1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ---------- ----------
Acquisition costs ........................... $ 163,786 $ 108,645 $ 35,047 $ 3,876 $ 14,834 $ 1,384
Exploration costs ........................... 38,350 23,845 10,672 3,833 -- --
Development costs ........................... 18,272 18,272 -- -- -- --
Capitalized interest ........................ 12,318 8,550 2,685 1,031 52 --
---------- ---------- ---------- ---------- ---------- ----------
$ 232,726 $ 159,312 $ 48,404 $ 8,740 $ 14,886 $ 1,384
========== ========== ========== ========== ========== ==========
As part of its on-going operations, the Company continually sells producing
and undeveloped reserves and related assets. Significant acquisitions and
dispositions for the five years ending December 31, 1997 are discussed below.
1997 TRANSACTIONS
On March 7, 1997, the Company completed an acquisition of certain interests
in various state leases in the Main Pass Block 69 field (the Main Pass
Acquisition), offshore Plaquemines Parish, Louisiana, for a net purchase price
of $55.9 million. The Main Pass Acquisition included interests situated
contiguous to the Company's existing Main Pass 69 holdings acquired from Shell
Oil Company, its affiliates and subsidiaries (Shell) in June 1992.
On October 15, 1997, the Company acquired certain oil and gas interests in
various federal leases in the South Pass 61 and 65 fields (the South Pass
Properties) from Shell for a net purchase price of $59.9 million. The Company
acquired a 50% working interest in the fields and became operator of the
properties. The acquisition included interests in 95 producing wells located on
approximately 26,250 gross acres. Also on October 15, 1997, the Company entered
into an exploratory joint venture agreement with Shell which establishes an Area
of Mutual Interest (AMI) covering approximately 240 square miles located in
coastal and offshore areas of Plaquemines Parish, Louisiana. Under the terms of
the oil and gas exploration agreement, the Company and Shell have agreed to
contribute existing leasehold, project inventory and proprietary 3-D seismic
data within the AMI. The Company expects the venture to spud the initial
exploratory well in 1998.
In 1997, the Company acquired additional interests in various properties it
operates and in which it holds an existing working interest position from
several of its institutional partners. The net cost of the additional interests
acquired from the Company's institutional partners was approximately $49.6
million. In addition, the Company acquired interests in other North American
properties for total consideration of $13.0 million.
During 1997, the Company sold additional non-strategic North American
properties for total proceeds of $19.4 million.
1996 TRANSACTIONS
On September 26, 1996, the Company acquired from Mobil Oil and Producing
Southeast, Inc. (Mobil), certain interests in eleven oil and gas producing
fields and related production facilities primarily situated in the shallow
federal waters of the central Gulf of Mexico, offshore Louisiana (the Central
Gulf Properties), for approximately $117.6 million. At December 31, 1996, one of
the eleven Central Gulf Properties was included in Inventory. The subject
property was sold on January 3, 1997, for $37.2 million. No gain or loss was
recognized on the sale.
In 1995, the Company agreed to assign to Yukong Limited a portion of its
interests in Blocks CI-01 and CI-02 in Cote d'Ivoire and Blocks B, C and D in
Equatorial Guinea. Mobil Equatorial Guinea, Inc. subsequently exercised its
preferential right to purchase the interest in Block B in lieu of the proposed
assignment to Yukong Limited. Under the agreements, the Company received $40.1
million in cash in 1996 and 1995.
In June 1996, UMC Resources Canada Ltd. (Resources), the Company's
wholly-owned Canadian subsidiary, sold all of its interest in the Rocanville
area in the province of Saskatchewan, effective May 1, 1996. Net proceeds from
the sale were $6.7 million.
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In September 1996, the Company executed an agreement with Shell Exploration
Africa B.V. to sell a 55% contract interest in Block CI-105 in Cote d'Ivoire for
total cash proceeds of $3.3 million, including $0.9 million relating to
reimbursement of certain exploration costs.
During 1996, the Company sold various other non-strategic North American
properties for total proceeds of $22.1 million.
1995 TRANSACTIONS
In February 1995, the Company sold all of its interest in oil and gas
properties in West Virginia, effective January 1, 1995. Net proceeds from the
sale were $41.2 million.
In March 1995, the Company sold all of its interest in the Main Pass 108
offshore Louisiana field effective February 1, 1995. Net proceeds from the sale
were $6.9 million.
In October 1995, the Company and its institutional partners acquired
certain oil and natural gas properties at a cost of $58.6 million (approximately
$21.3 million net to the Company). The acquired interests relating to one of the
institutional partners (in an additional amount of approximately $10.3 million)
were included in inventory until January 1996, at which time the partner
reimbursed the Company for its proportionate share of the acquisition, including
carrying costs. A separate short-term facility was negotiated for the financing
of this interest in the properties and was paid at closing in January 1996.
1994 TRANSACTIONS
On November 15, 1994, the Company completed the acquisition of all
outstanding common stock of General Atlantic Resources, Inc. (GARI), 51% of
which was purchased for cash of $129.2 million and the remainder of which was
acquired in exchange for common stock. The acquisition was accounted for under
the purchase method and, as a result, the assets and liabilities of GARI were
added to the Company's balance sheet as of September 19, 1994, at amounts that
reflect the purchase price of 51% of GARI's equity. On November 15, 1994, the
remainder of GARI's equity was acquired by exchange of stock and was recorded as
additional basis in the assets acquired.
On December 28, 1993, Ocean Energy, Inc., a Louisiana corporation (Ocean
Louisiana), transferred its interest in substantially all of its oil and gas
properties to Ocean Energy LLC (Ocean LLC) in return for an 87.5% ownership
interest. The remaining 12.5% was owned by an unrelated party, Franks Petroleum,
Inc. (Franks). On December 7, 1994, Ocean Louisiana was merged into a
wholly-owned subsidiary of the Company and the Company acquired Franks' interest
in Ocean LLC for $6 million and recorded the acquisition using the purchase
method.
1993 TRANSACTIONS
In 1993, the Company acquired the stock of three privately owned oil and
gas companies, Norfolk Holdings Inc. (NHI), KPX, Inc. (KPX) and Sterling Energy
Limited (SEL). The acquisitions were accounted for under the purchase method. As
a result, the assets and liabilities of NHI, KPX and SEL were added to the
Company's balance sheet at amounts that reflect the purchase prices rather than
the historical costs reported by the acquired companies.
NHI: On April 30, 1993, the Company purchased for cash the equity of
NHI for $119.6 million, including acquisition costs.
KPX: On June 11, 1993, the Company acquired KPX for $16.6 million with
shares of Series E Convertible Preferred Stock (which was converted to
Common Stock upon the effective date of the UMC's initial public
offering), cash of $0.6 million, warrants to purchase common shares and
repayment of $7.3 million of senior bank debt of KPX.
SEL: On October 29, 1993, the Company purchased the outstanding stock
of SEL for $6.9 million.
On June 11, 1992, the Company acquired Main Pass 69 from Shell for $39.2
million. On June 10, 1993, the Company acquired an interest in the South Pass 24
and 27 fields (the East Bay Fields, and together with the related platforms and
facilities, the East Bay Complex) from Shell for $131.9 million. Concurrent with
these acquisitions, the Company assigned overriding royalty interests burdening
one-eighth of the working interests to a company owned by a stockholder for
services rendered in connection with the acquisitions. In addition, the Company
sold to Franks a one-eighth working interest subject
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to the override in return for the assumption of one-eighth of the volumetric
production payment liabilities related thereto and, for the East Bay Complex,
one-eighth of a note payable to Shell.
Concurrent with the Main Pass 69 and East Bay Complex acquisitions, the
Company sold to Enron Reserve Acquisition Corp. (ERAC) nonrecourse volumetric
production payments interests of approximately $36.7 million and $95.7 million,
respectively, net of the amounts assumed by Franks. The Company deferred the
revenue associated with the sale of these production payment interests because a
substantial obligation for future performance existed. Under the terms of the
sales, the Company was obligated to deliver the production payment volumes free
and clear of lease operating expenses, production taxes, plugging and
abandonment and other capital costs. The deferred revenue was amortized on the
unit-of-production method and recognized as oil and gas revenues as the
associated hydrocarbons were delivered. In addition, under separate agreements,
the Company was required to sell all excess production over production payment
volumes from the subject properties to an affiliate of ERAC during the same
periods.
In connection with the East Bay Complex production payment, Enron Finance
Corp. (Enron) obtained from the Company the right to acquire during a ten-year
period commencing January 1, 1996, (or upon a registration of securities), at a
nominal cost, a one-eighth working interest in the East Bay Complex or a 9%
interest in Ocean LLC (the Enron Option). If the working interest was acquired,
it would have been burdened by its share of the production payment. For
accounting purposes, the total proceeds received by the Company from ERAC
related to the East Bay Complex production payment were allocated between
deferred revenue from the sale of the production payment interest ($95.7
million) and a reduction in the full cost pool resulting from the sale of a
portion of the Company's interest in East Bay Complex ($7.5 million) based upon
the relationship of one-eighth of post-January 1, 1996 reserves to total
reserves, as determined at the date of acquisition. The production payment
volumes attributed to this interest were 401 MBbls and 1,369 MMcf. Reserve
information for 1993 and production payment volumes reflected above are
presented net of this one-eight interest. In December 1994, Enron contributed
its Enron Option and $1,000 in exchange for 2.3 million shares of the Company's
common stock. As a result of the exchange, the Company recorded a $7.5 million
increase to oil and gas properties as well as an increase of $7.5 million for
the related production payment obligation, both of which were originally reduced
from the respective accounts.
Concurrent with the December 7, 1994 initial public offering (OEI Initial
Offerings), the Company repurchased the production payment interests. The cost
to acquire the production payment liability exceeded its book value by
approximately $15.7 million. This excess represented the difference between the
amount paid and the book value of the production payment liability as of
December 7, 1994. This excess was recorded as an expense in the period acquired.
NOTE 4 RESTRICTED DEPOSITS
The Company, as the operator of certain oil and gas properties, is a party
to two escrow agreements. The first, related to its interest in the East Bay
Fields, requires monthly deposits of $100,000 through June 30, 1998, and
$350,000 thereafter until the balance in the escrow account equals $40.0 million
unless the Company commits to the plugging and abandonment of a certain number
of wells in which case the increase will be deferred. The second agreement,
related to its interest in the Main Pass 69 field, required an initial deposit
of $250,000 and monthly deposits thereafter of $50,000 until the balance in the
escrow account equals $7.5 million. These deposits are to provide for the future
plugging and abandonment costs associated with the oil and gas properties. Such
funds are restricted as to withdrawal by the agreements. With respect to any
specifically planned plugging and abandoning operation, funds are partially
released when the Company presents to the escrow agent the planned plugging and
abandoning operations approved by the applicable governmental agency, with the
balance released upon the presentation by the Company to the escrow agent of
evidence from the governmental agency that the operation was conducted in
compliance with applicable laws and regulations. The escrow agent for both
agreements is an unrelated financial institution. As of December 31, 1997, 1996,
1995, 1994 and 1993, the escrow balances were approximately $8.5 million, $6.3
million, $4.3 million, $2.3 million and $0.9 million (inclusive of Franks' share
of $0.1 million), respectively.
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NOTE 5 DEBT
Long-term debt consisted of the following at December 31, 1997, 1996, 1995,
1994 and 1993 (in thousands):
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
Revolving credit facility ................... $ 30,500 $ -- $ 32,200 $ 4,500 $ --
Global credit facility ...................... 126,496 -- 61,049 237,784 90,299
13 1/2% senior notes ........................ 245 125,000 125,000 125,000 --
10 3/8% senior subordinated notes ........... 150,000 150,000 150,000 -- --
9 3/4% senior subordinated notes ............ 159,230 159,142 -- -- --
8 7/8% senior subordinated notes ............ 199,677 -- -- -- --
Cote d'Ivoire project loan .................. -- -- 35,000 -- --
Note payable to shareholder ................. -- -- -- 10,000 --
Note payable to Shell ....................... -- -- 15,184 14,290 13,448
Other ....................................... 7,061 7,858 2,042 2,099 1,850
---------- ---------- ---------- ---------- ----------
673,209 442,000 420,475 393,673 105,597
Less: current maturities ................... (911) (1,026) (3,984) -- --
---------- ---------- ---------- ---------- ----------
$ 672,298 $ 440,974 $ 416,491 $ 393,673 $ 105,597
========== ========== ========== ========== ==========
Current maturities of long-term debt at December 31, 1997 by calendar year
are as follows (in thousands):
1998................................................................................................. $ 911
1999................................................................................................. 911
2000................................................................................................. 31,411
2001................................................................................................. 911
2002................................................................................................. 127,407
Thereafter........................................................................................... 511,658
-------------
$ 673,209
=============
OEI CREDIT FACILITY
Concurrent with the closing of the Merger on March 27, 1998, the Company
entered into a $750.0 million five-year unsecured revolving credit facility (OEI
Credit Facility) which combines and replaces both the Revolving Credit Facility
and the Global Credit Facility discussed below. As of March 1998, the OEI Credit
Facility provides a $600.0 million initial borrowing base. As of March 31, 1998,
total borrowings outstanding against the facility were approximately $265.0
million, leaving approximately $335.0 million of available credit.
REVOLVING CREDIT FACILITY
The Revolving Credit Facility, governed by the Second Amended and Restated
Credit Agreement among Ocean Energy, Inc. and The Chase Manhattan Bank (Chase),
as Agent, (the Credit Agreement), was a three year term facility maturing on
October 31, 2000, unless the maturity date was extended in accordance with the
Credit Agreement. The banks associated with the Credit Agreement committed to a
$250.0 million facility and a $200.0 million borrowing base.
At the Company's option, borrowings under the Revolving Credit Facility bore
interest either at the base rate (the higher of the federal funds rate plus 0.5%
per annum or the Agent's prime commercial lending rate) or the London Interbank
Offered Rate (LIBOR), in the latter case plus an applicable margin of 125 to 175
basis points, depending upon the percentage of usage on the Revolving Credit
Facility. As of December 31, 1997, the Company had no outstanding letters of
credit under its Revolving Credit Facility.
GLOBAL CREDIT FACILITY
As of January 1997, the Global Credit Facility provided a borrowing base
amount of $200.0 million. During March 1997, the Company expanded the Global
Credit Facility to $300.0 million with an initial borrowing base of $275.0
million. In November 1997, the borrowing base was increased to $300.0 million.
16
18
The Global Credit Facility, which was with a group of commercial banks,
consisted of two parts: (i) a credit facility among the Company, certain of its
subsidiaries and certain lenders (the U.S. Lenders) pursuant to which the U.S.
Lenders agreed to make a portion of the Global Credit Facility (subject to
Borrowing Base limitations) available to the Company (U.S. Credit Facility) and
(ii) a credit facility between the Company and certain lenders (the Canadian
Lenders) pursuant to which the Canadian Lenders agreed to make the remaining
part of the Global Credit Facility (subject to aggregate Borrowing Base
limitations under the U. S. Credit Facility and a specific Canadian Borrowing
Base sub-limit) available to the Company (the Canadian Credit Facility). The
amount of the Borrowing Base, which governed the aggregate Global Credit
Facility jointly under both the U.S. Credit Facility and the Canadian Credit
Facility, and the sub-limit on the portion of the Global Credit Facility made by
the Canadian Lenders, were both determined on an annual basis jointly by the
U.S. Lenders and the Canadian Lenders.
The Global Credit Facility had a term of five years with amortization of
the Borrowing Base to begin in 1999, unless extended or modified by the Company
and the commercial banks. At December 31, 1997, the Company had outstanding
loans thereunder of approximately $126.5 million.
During 1997, 1996, 1995, 1994 and 1993, the Global Credit Facility provided
the Company with various interest rate options based upon prime and LIBOR rates.
13 1/2% SENIOR NOTES
On December 7, 1994, in conjunction with the OEI Initial Offerings, the
Company completed an offering of $125.0 million of 13 1/2% Senior Notes due
December 1, 2004, (the 13 1/2% Notes). Interest was payable semi-annually on
June 1 and December 1 of each year, commencing June 1, 1995. On July 22, 1997,
the Company amended the indenture governing its 13 1/2% Notes and purchased
approximately $124.8 million of the $125.0 million in original principal amount
of the 13 1/2% Notes for approximately $151.5 million. This purchase resulted in
an extraordinary charge of $19.3 million, net of a deferred tax benefit of $11.6
million. The extraordinary charge represented the difference between the
purchase price and related expenses and the net carrying value of the 13 1/2%
Notes.
10 3/8% SENIOR SUBORDINATED NOTES
On October 30, 1995, the Company completed a public offering of $150.0
million of 10 3/8% Senior Subordinated Notes (10 3/8% Notes) due 2005 at an
initial price of 99.5% of face value. Proceeds of $144.9 million (after
deducting underwriting discounts, commission and expenses of the offering) were
used to reduce debt under the Global Credit Facility. Interest is payable
semiannually on April 15 and October 15 of each year, commencing April 15,
1996. The 10 3/8% Notes are general unsecured senior obligations of the Company
and are guaranteed by Ocean Louisiana, but are subordinate to the OEI Credit
Facility. The 10 3/8% Notes are redeemable at the option of the Company, in
whole or in part, at anytime after October 15, 2000 at certain premiums to face
value.
9 3/4% SENIOR SUBORDINATED NOTES
On September 26, 1996, the Company completed the offering of 9 3/4% Senior
Subordinated Notes due 2006 (9 3/4% Notes) at a discount for net proceeds of
approximately $154.0 million (after offering costs). Interest on the 9 3/4%
Notes is payable semi-annually on April 1 and October 1 of each year. The 9 3/4%
Notes are general unsecured senior obligation of the Company and are guaranteed
by Ocean Louisiana, but are subordinate to the OEI Credit Facility. Proceeds to
the Company were used primarily to complete the acquisition of the Central Gulf
Properties.
8 7/8% SENIOR SUBORDINATED NOTES
On July 2, 1997, the Company completed the offering of 8 7/8% Senior
Subordinated Notes due 2007 (8 7/8% Notes) at a discount for proceeds of
approximately $195.2 million (after offering costs). Interest is payable
semi-annually on January 15 and July 15 of each year. The 8 7/8% Notes are
general unsecured senior obligation of the Company and are guaranteed by Ocean
Louisiana, but are subordinate to the OEI Credit Facility. Proceeds to the
Company were used primarily to finance the purchase of the 13 1/2% Notes and to
repay outstanding indebtedness under the Revolving Credit Facility.
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COTE D'IVOIRE PROJECT LOAN
In July 1995, a subsidiary of the Company entered into the Cote d'Ivoire
Facility with the International Finance Corporation (IFC) in connection with the
development of Block CI-11 offshore Cote d'Ivoire. As of December 31, 1995,
$35.0 million was outstanding under the Cote d'Ivoire Facility. In November
1996, the Cote d'Ivoire Facility was purchased by the Company, paying off the
IFC in full with a portion of the proceeds of the November 1996 offering of
common stock.
NOTE PAYABLE TO SHAREHOLDER
In February 1994, the Company agreed to reacquire 2,340 shares of stock
from a former shareholder for $10.0 million (two notes in the amount of $5.0
million each). The notes were due March 1, 1995, bore interest and were payable
monthly, at an annual rate of 8%. The payment of these notes was made on March
1, 1995, using funds drawn on the Revolving Credit Facility and, as such, has
been classified as long-term debt at December 31, 1994.
NOTE PAYABLE TO SHELL
In connection with the acquisition of the East Bay Complex in June 1993,
the Company acquired a note payable to Shell of $13.0 million (the Shell Note).
Accrued interest on the Shell Note was $2.2 million, $1.3 million and $0.4
million at December 31, 1995, 1994 and 1993, respectively. The Shell Note was
repaid on March 29, 1996.
OTHER LONG-TERM DEBT
Havre Pipeline Company LLC, a limited liability corporation in which the
Company had a 56% interest at December 31, 1997, entered into a credit agreement
(Havre Credit Agreement) which provided a Term Loan due September 30, 2005. The
Company's proportionate share outstanding at December 31, 1997 is $7.1 million,
including current maturities. Principal installments are due at the end of each
quarter. Additional principal payments may be required under the Havre Credit
Agreement if operating cash flows of the limited liability corporation exceed
predetermined levels.
Unsecured Notes payable in the amount of $1.9 million were outstanding at
December 31, 1995 and 1994. These notes were paid in full in August 1996. A
promissory note to Union Planters Bank was collateralized by a company-owned
seaplane and bore interest at the Wall Street Prime rate. The balance of the
note was paid February 10, 1997. A capital lease from Green Tree Vendor Services
Corp. in the amount of $0.1 million was collateralized by certain computer
equipment and paid in August 1997.
On June 11, 1994, Ocean LLC entered into two loan agreements with Joint
Energy Development Investments Limited Partnership (JEDI), a venture between
California Public Employees Retirement System and Enron Capital Corporation. The
first was a $20.0 million term loan, bearing interest at 12.5% payable monthly,
maturing on June 11, 1997. The second loan, the development loan, provided for
draws up to a maximum of $40.0 million, bearing interest at 15% payable monthly.
In connection with this loan, the Company conveyed to JEDI a 20% overriding
royalty interest (defined to be net of production costs) on certain unevaluated
interests which commenced upon payment in full of the development loan. This
interest was purchased from JEDI in December 1994, for $4.25 million. Proceeds
from the OEI Initial Offerings were used to repay these loans in December 1994.
OTHER DISCLOSURES
Effective January 18, 1994, the Company entered into five-year fixed LIBOR
interest rate swap contracts that provide for fixed interest rates to be
realized on notional amounts of $30.0 million in 1994 and $45.0 million from
1995 through 1998. The agreement includes varying annual fixed interest rates
ranging from 3.66% in 1994 to 6.40% in 1998, plus interest rate margins. In 1995
and 1996, the Company had in place a two-year LIBOR interest rate cap contract
on an additional notional amount of $45.0 million at interest rate caps of 7.60%
and 8.30%, respectively, plus interest rate margins.
NOTE 6 CAPITAL STOCK
COMMON STOCK
In 1997, the Company adopted a shareholder rights plan (the Rights Plan),
pursuant to which preferred stock purchase rights (the Rights) have been
distributed to holders of the Company's common stock. The Rights Plan is
designed to deter
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20
coercive takeover tactics and to prevent an acquirer from attempting to gain
control of the Company without negotiating with the Board of Directors. The
Company is not aware of any effort to acquire control of the Company, but
adopted the Rights Plan concurrently with its execution of the Agreement and
Plan of Merger.
The Rights will expire on December 22, 2007. The Rights will be exercisable
only if a person acquires beneficial ownership of 15 percent or more of the
Company's common stock (an Acquiring Person), or commences a tender offer which
would result in ownership of 15 percent or more of such stock. Under the Rights
Plan, one Right to purchase one one-hundredth of a share of a new series of
junior preferred stock of the Company at an exercise price of $240.00 per one
one-hundredth of a share (subject to adjustment) was issued for each outstanding
share of the Company's common stock held at the close of business on January 9,
1998 (the Record Date).
Under certain circumstances, the Rights "flip in" and enable the holders
(other than an Acquiring Person) to buy the Company's common stock at a 50
percent discount. Under other circumstances, the Rights "flip over" and entitle
the holders (other than an Acquiring Person) to buy shares of the acquirer's
common stock at a 50 percent discount.
The Company will generally be entitled to redeem the Rights in whole, but
not in part, at $0.001 per Right payable in cash or common stock, subject to
adjustment, at any time until 10 business days (subject to extension) after the
first public announcement that an Acquiring Person has become such.
The Company has authorized 250,000,000 shares of common stock, 8,000,000
shares of preferred stock and 2,000,000 shares of junior preferred stock.
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21
The following table summarizes the calculation of annual weighted average
common shares outstanding for purposes of the computations of earnings per share
(in thousands):
YEARS ENDED DECEMBER 31,
-------------------------------------------------
1997 1996 1995 1994 1993
-------- ------- ------- -------- --------
Shares outstanding from beginning of period ..................... 91,742 71,799 71,138 67,936 26,669
Exercise of stock options and warrants .......................... 600 795 277 1,002 --
Adjustment to reflect 1 for 2 reverse stock split ............... -- -- -- -- (3,683)
Conversion of Series F Preferred Stock .......................... -- 1,043 -- -- --
Common shares issued in July 1993 offering ...................... -- -- -- -- 2,539
Common shares issued in December 1994 offering .................. -- -- -- 1,039 --
Issuance of common stock ........................................ -- -- -- -- 9,653
Repurchase of common stock ...................................... -- -- -- (14,494) --
Common shares issued upon conversion of preferred stock ......... -- -- -- -- 8,842
Common shares issued in connection with exercise
of underwriters' over allotment ............................. -- -- 91 -- --
Common shares issued - bonus shares ............................. -- -- 9 -- --
Common shares issued in November 1997 offering .................. 973 -- -- -- --
Common shares issued in March 1996 offering ..................... -- 8,258 -- -- --
Common shares issued in November 1996 offering .................. -- 789 -- -- --
-------- ------- ------- -------- --------
Weighted average number of common shares outstanding ............ 93,315 82,684 71,515 55,483 44,020
Common stock equivalents of stock options and warrants .......... 3,331 3,221 1,890 -- 755
-------- ------- ------- -------- --------
Weighted average number of common shares and
common share equivalents outstanding ......................... 96,646 85,905 73,405 55,483 44,775
======== ======= ======= ======== ========
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NOTE 7 INCOME TAXES
Under the provisions of SFAS No. 109, the components of the net deferred
income tax assets and liabilities recognized in the Company's Supplemental
Consolidated Balance Sheet at December 31, 1997, 1996, 1995, 1994 and 1993 were
as follows (in thousands):
1997 1996
----------------------------------------- -----------------------------------------
FEDERAL FOREIGN STATE TOTAL FEDERAL FOREIGN STATE TOTAL
-------- -------- -------- -------- -------- -------- -------- --------
Deferred tax assets -
Net operating loss
carryforward .................. $ 42,952 $ 16,774 $ 4,956 $ 64,682 $ 44,424 $ 13,115 $ 5,544 $ 63,083
Percentage depletion
carryforward .................. 2,508 -- 131 2,639 2,333 -- 229 2,562
Investment tax credit
carryforward .................. 989 -- -- 989 1,720 -- -- 1,720
Alternative minimum tax
credit carryforward ........... 3,964 -- -- 3,964 3,662 -- -- 3,662
Deferred foreign tax
credit carryforward ........... 920 -- -- 920 3,790 -- -- 3,790
Other ........................... 79 -- 4 83 50 -- 4 54
Valuation allowance ............. (2,971) -- (70) (3,041) (3,551) -- (151) (3,702)
-------- -------- -------- -------- -------- -------- -------- --------
48,441 16,774 5,021 70,236 52,428 13,115 5,626 71,169
-------- -------- -------- -------- -------- -------- -------- --------
Deferred tax liabilities -
Excess of basis in oil
and gas properties
for financial reporting
purposes over the tax
basis ......................... 45,760 25,436 5,911 77,107 31,521 25,332 5,526 62,379
Other ........................... 1,186 -- 1,425 2,611 1,186 -- 1,330 2,516
-------- -------- -------- -------- -------- -------- -------- --------
46,946 25,436 7,336 79,718 32,707 25,332 6,856 64,895
-------- -------- -------- -------- -------- -------- -------- --------
Net deferred tax asset
(liability) ................... 1,495 (8,662) (2,315) (9,482) 19,721 (12,217) (1,230) 6,274
Current portion of deferred
tax assets classified as
current asset ................... 1,365 -- 182 1,547 2,836 -- 3 2,839
-------- -------- -------- -------- -------- -------- -------- --------
Total non-current deferred tax
asset (liability) ............... $ 130 $ (8,662) $ (2,497) $(11,029) $ 16,885 $(12,217) $ (1,233) $ 3,435
======== ======== ======== ======== ======== ======== ======== ========
1995 1994
----------------------------------------- -----------------------------------------
FEDERAL FOREIGN STATE TOTAL FEDERAL FOREIGN STATE TOTAL
-------- -------- -------- -------- -------- -------- -------- --------
Deferred tax assets -
Net operating loss
carryforward .................. $ 44,135 $ 5,338 $ 4,037 $ 53,510 $ 57,385 $ -- $ 3,791 $ 61,176
Percentage depletion
carryforward .................. 2,158 -- 174 2,332 1,983 -- 172 2,155
Investment tax credit
carryforward .................. 2,619 -- -- 2,619 3,447 -- -- 3,447
Alternative minimum tax
credit carryforward ........... 3,276 -- -- 3,276 2,634 -- -- 2,634
Deferred foreign tax
credit carryforward ........... 1,138 -- -- 1,138 -- -- -- --
Other ........................... 891 -- 51 942 3,695 81 3,776
Valuation allowance ............. (4,257) -- (79) (4,336) (5,645) -- (105) (5,750)
-------- -------- -------- -------- -------- -------- -------- --------
49,960 5,338 4,183 59,481 63,499 -- 3,939 67,438
-------- -------- -------- -------- -------- -------- -------- --------
Deferred tax liabilities -
Excess of basis in oil
and gas properties
for financial reporting
purposes over the tax
basis ......................... 16,176 13,743 3,659 33,578 32,997 6,801 4,372 44,170
Other ........................... 1,253 -- 1,985 3,238 1,298 -- 1,087 2,385
-------- -------- -------- -------- -------- -------- -------- --------
17,429 13,743 5,644 36,816 34,295 6,801 5,459 46,555
-------- -------- -------- -------- -------- -------- -------- --------
Net deferred tax asset
(liability) ................... 32,531 (8,405) (1,461) 22,665 29,204 (6,801) (1,520) 20,883
Current portion of deferred
tax assets classified as
current asset ................... 3,727 -- 148 3,875 15,000 -- 498 15,498
-------- -------- -------- -------- -------- -------- -------- --------
Total non-current deferred tax
asset (liability) ............... $ 28,804 $ (8,405) $ (1,609) $ 18,790 $ 14,204 $ (6,801) $ (2,018) $ 5,385
======== ======== ======== ======== ======== ======== ======== ========
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1993
-----------------------------------------
FEDERAL FOREIGN STATE TOTAL
-------- -------- -------- --------
Deferred tax assets -
Net operating loss carryforward ........... $ 45,605 $ -- $ 3,112 $ 48,717
Excess of tax basis in stock of Canadian
subsidiary over basis for financial
reporting purposes ...................... 4,690 -- -- 4,690
Percentage depletion carryforward ......... 1,808 -- 148 1,956
Investment tax credit carryforward ........ 3,052 -- -- 3,052
Alternative minimum tax credit
carryforward ............................. 1,091 -- -- 1,091
Deferred foreign tax credit carryforward...
Other ..................................... 2,204 -- 118 2,322
Valuation allowance ....................... (4,361) -- (393) (4,754)
-------- -------- -------- --------
54,089 -- 2,985 57,074
-------- -------- -------- --------
Deferred tax liabilities -
Excess of basis in oil and gas
properties for financial reporting
purposes over the tax basis ............. 22,243 16,803 3,907 42,953
Other ..................................... 1,186 -- 921 2,107
-------- -------- -------- --------
23,429 16,803 4,828 45,060
-------- -------- -------- --------
Net deferred tax asset (liability) .......... 30,660 (16,803) (1,843) 12,014
Current portion of deferred tax assets
classified as current asset ............. 3,569 -- 103 3,672
-------- -------- -------- --------
Total non-current deferred tax asset
(liability).............................. $ 27,091 $(16,803) $ (1,946) $ 8,342
======== ======== ======== ========
As of December 31, 1997 and 1996, the Company and its subsidiaries had
U.S. federal net operating loss (NOL) carryforwards of approximately $122.7
million and $127.0 million, respectively, and Equatorial Guinea NOL
carryforwards of approximately $67.0 million and $52.0 million, respectively.
The Company's Canadian subsidiary also had $32.2 million and $17.6 million in
Canadian Tax Pool carryforwards as of December 31, 1997 and 1996, respectively.
The Company is subject to taxation under the laws of Cote d'Ivoire,
Equatorial Guinea and other foreign jurisdictions. Income taxes in these
jurisdictions will be taken as a credit or deduction against the Company's
United States tax liability.
Management believes the Company will realize the benefit of all NOLs.
Accordingly, the Company has recognized a deferred tax asset relating to these
carryforwards. The U.S. federal NOLs expire as follows (in thousands):
1998................................................................ $ --
1999................................................................ 400
2000................................................................ 23,900
2001................................................................ 16,500
2002................................................................ 6,300
2003................................................................ 1,200
2004................................................................ 19,400
2005................................................................ 3,200
Beyond 2005......................................................... 51,800
-----------
$ 122,700
===========
For federal income tax purposes, certain limitations are imposed on an
entity's ability to utilize its NOLs in future periods if a "change of control",
as defined for federal income tax purposes, has taken place. In general terms,
the limitation on utilization of NOLs and other tax attributes during any one
year is determined by the value of an acquired entity at the date of the "change
of control" multiplied by the then-existing long-term, tax-exempt interest rate.
The manner of determining an acquired entity's "value" has not yet been
addressed by the Internal Revenue Service. The Company has determined that, for
federal income tax purposes, a "change of control" occurred as a result of the
stock purchases made by the Company's shareholders, and future utilization of
NOLs will be limited in the manner described above. The use of NOLs acquired as
a result of corporate acquisitions
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24
were already subject to limitations computed at the time of each acquisition.
While the effect of such limitations may be to defer the use of existing NOL
carryforwards, the Company does not believe such limitations will impact the
Company's ability to fully utilize the NOLs.
As of December 31, 1997, 1996, 1995, 1994 and 1993, the Company and its
subsidiaries had investment tax credit carryforwards of approximately $1.0
million, $1.7 million, $2.6 million, $3.4 million and $3.0 million,
respectively. To the extent not utilized, these carryforwards will expire in the
years 1998 through 2001. For purposes of computing the net deferred tax
liability as of December 31, 1997, 1996, 1995, 1994 and 1993, none of these
carryforwards were utilized.
The components of the Income tax provision (benefit) recognized on the
Supplemental Consolidated Statement of Income are as follows (in thousands):
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
Current taxes -
Federal .................................... $ 169 $ 455 $ 340 $ (323) $ 264
Foreign .................................... 4,716 98 (370) 409 492
State ...................................... 1,335 232 362 (61) 375
---------- ---------- ---------- ---------- ----------
6,220 785 332 25 1,131
---------- ---------- ---------- ---------- ----------
Deferred taxes -
Federal .................................... 28,278 21,769 (3,116) (49,711) (2,280)
Foreign .................................... 5,408 3,888 1,113 (12,524) 955
State ...................................... 1,086 (227) (65) (4,866) (618)
---------- ---------- ---------- ---------- ----------
34,772 25,430 (2,068) (67,101) (1,943)
---------- ---------- ---------- ---------- ----------
Total income tax provision (benefit) .......... $ 40,992 $ 26,215 $ (1,736) $ (67,076) $ (812)
========== ========== ========== ========== ==========
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The following is a reconciliation of the income tax provision (benefit)
computed by applying the federal statutory income tax rate to net income (loss)
before income taxes to the Income tax provision (benefit) shown on the
Supplemental Consolidated Statement of Income (in thousands):
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
Income tax provision (benefit) computed at the
federal statutory rate of 35% .............................. $ 36,125 $ 28,425 $ 1,336 $(66,239) $ 3,749
State and local taxes (net of federal effect) ................... 1,430 (610) (340) (2,785) (213)
Foreign income taxes (net of federal effect) .................... 2,977 -- -- -- --
Tax effect of:
Provision (benefit) for net book deductions not
available for tax due to differences in book/tax
basis .................................................... 329 499 (677) 4,956 (2,866)
Excess of taxes on foreign income over federal
statutory rate ........................................... 43 291 165 381 475
Benefit of deferred foreign tax credit carryforward ......... -- -- (1,138) -- --
Provision (benefit) resulting from adjustments
from estimate to actual in estimating taxable income ..... 459 (2,139) (181) (6,227) (901)
Increase attributable to non-taxable period ................. -- -- -- 1,622 --
Alternative minimum tax credit carryforward benefit ......... (151) (193) (321) 141 (546)
Increase in tax rate ........................................ -- -- -- -- (482)
Other ....................................................... (220) (58) (580) 1,075 (28)
-------- -------- -------- -------- --------
Income tax provision (benefit) .................................. $ 40,992 $ 26,215 $ (1,736) $(67,076) $ (812)
======== ======== ======== ======== ========
NOTE 8 EMPLOYEE BENEFIT PLANS
STOCK OPTION PLANS
At December 31, 1997, the Company had six non-qualified stock option plans:
AUTHORIZED AVAILABLE
SHARES OUTSTANDING FOR ISSUANCE
------------- ------------ ------------
1987 Employee Plan .............................................. 2,210,000 758,874 --
1994 Employee Plan .............................................. 5,265,000 2,567,378 1,494,164
1994 Outside Directors Plan ..................................... 325,000 195,000 126,100
1994 Long Term Incentive Plan ................................... 3,510,000 3,024,852 1,114
1996 Long Term Incentive Plan ................................... 2,340,000 1,064,700 1,275,300
Long Term Incentive Plan for Non-Executive Employees ............ -- 1,723,796 --
------------- ------------ ------------
13,650,000 9,334,600 2,896,678
============= ============ ============
The plans provide that directors, officers and key employees may be awarded
options to purchase Common Stock of the Company at a price equal to the market
value of OEI Common Stock on the award date. New options granted will vest over
a three-year period. As a result of the Merger, virtually all options
outstanding became fully vested and are exercisable by the optionees. The
following table reflects summarized information about stock options outstanding
at December 31, 1997:
Options Outstanding Options Exercisable
------------------------------------------- -----------------------------
Weighted
Average Weighted Weighted
Number Remaining Average Number Average
Range of Outstanding Contractual Exercise Exercisable Exercise
Exercise Price at 12/31/97 Life (in years) Price at 12/31/97 Price
- ----------------- ----------- --------------- ---------- ----------- ---------
$ 2.00 to $ 6.75 2,912,587 6.9 $ 4.67 2,388,570 $ 4.55
$ 7.60 to $12.00 2,481,609 6.6 $ 9.11 1,285,757 $ 8.83
$13.80 to $18.37 1,621,230 9.0 $16.03 233,379 $13.92
$19.50 to $29.25 1,985,074 9.7 $21.84 14,300 $22.69
$33.90 to $36.55 334,100 9.8 $33.99 245,050 $33.95
----------- ----------
9,334,600 4,167,056
=========== ==========
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A summary of actual options granted and exercised follows:
1997 1996 1995
----------- ------------ -----------
Option shares outstanding -
Beginning of year ............... 8,090,322 7,592,666 5,649,885
Granted ......................... 2,423,590 2,510,690 2,584,010
Exercised ....................... (1,111,886) (1,393,281) (556,860)
Canceled ........................ (67,426) (619,753) (84,369)
----------- ------------ -----------
End of year ..................... 9,334,600 8,090,322 7,592,666
=========== ============ ===========
Shares available for grant at end of
year .................................. 2,896,678 678,687 928,895
Shares exercisable at end of year ..... 4,167,056 3,237,673 3,304,164
Average price of options exercised
during the year .................... $ 7.07 $ 5.78 $ 5.15
Average exercise price of options
outstanding at end of year ......... $ 12.34 $ 9.30 $ 6.36
Weighted average fair value of options
granted during the year ............ $ 10.56 $ 7.78 $ 2.81
Weighted average exercise price for
options granted during the year .... $ 20.87 $ 15.49 $ 6.29
The Company accounts for these plans under APB Opinion No. 25, Accounting
for Stock Issued to Employees, under which no compensation cost has been
recognized. Had compensation cost for these plans been determined consistent
with SFAS 123, Accounting for Stock-Based Compensation, the Company's reported
net income and earnings per share would have been adjusted to the following pro
forma amounts (in thousands, except per share amounts):
December 31,
----------------------------------------------------------------------------------------------------------
1997 1996 1995
---------------------------------- --------------------------------- ---------------------------------
As Basic Diluted As Basic Diluted As Basic Diluted
Reported Pro Forma Pro Forma Reported Pro Forma Pro Forma Reported Pro Forma Pro Forma
--------- --------- --------- --------- --------- --------- --------- --------- ---------
Net income before
extraordinary item $ 62,220 $ 55,302 $ 55,244 $ 55,000 $ 50,676 $ 50,647 $ 5,552 $ 5,099 $ 5,087
Net income after
extraordinary item $ 42,919 $ 36,001 $ 35,943 $ 55,000 $ 50,676 $ 50,647 $ 5,552 $ 5,099 $ 5,087
Earnings per common
share before
extraordinary item
Basic $ 0.67 $ 0.59 $ 0.65 $ 0.60 $ 0.06 $ 0.05
Diluted $ 0.64 $ 0.57 $ 0.62 $ 0.58 $ 0.06 $ 0.05
Earnings per common
share after
extraordinary item
Basic $ 0.46 $ 0.39 $ 0.65 $ 0.60 $ 0.06 $ 0.05
Diluted $ 0.44 $ 0.37 $ 0.62 $ 0.58 $ 0.06 $ 0.05
The fair value of each option is estimated on the date of grant using the
Black-Scholes option pricing model, with the following assumptions used for
grants in 1997, 1996 and 1995, respectively; risk-free interest rates of 6.16%
to 6.83%, 5.40% to 6.76% and 5.58% to 7.13%; expected dividend yields of 0%, 0%
and 0%; expected lives of 5.0 years to 6.5 years, 5.0 years to 6.5 years and
5.0 years to 6.5 years; and, expected volatility of 42.67% to 54.13%, 39.34% to
43.14% and 35.07% to 45.53%.
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27
SAVINGS PLAN
The Company maintains a defined contribution savings plans for the benefit
of its U.S. employees. During 1997, 1996 and 1995, the Company made
contributions to the Plans on behalf of all participants totaling $1.6 million,
$1.3 million, and $1.2 million, respectively.
Resources maintains a separate group savings plan for its employees. During
1997, 1996 and 1995, this subsidiary contributed $76,000, $67,000 and $63,000,
respectively, to the Plan for the benefit of its employees.
NOTE 9 MAJOR CUSTOMERS
The Company markets its oil and gas production to numerous purchasers under
a combination of short and long-term contracts. During 1997, 1996 and 1995,
Shell Oil Company accounted for 21%, 28% and 33%, respectively, of the Company's
oil and gas revenues. Mobil Sales and Supply Corporation accounted for 15% of
the Company's oil and gas revenues in 1997 as the purchaser of the Company's
production in Equatorial Guinea. In addition, during 1994 and 1993, Enron Corp.,
its subsidiaries and affiliates, accounted for 49% and 42% of the Company's oil
and gas revenues. Murphy Oil USA, Inc. accounted for 10% of the Company's oil
and gas revenues in 1995. During 1997, 1996, 1995, 1994 and 1993, the Company
had no other purchasers that accounted for greater than 10% of its oil and gas
revenues. The Company believes that the loss of any single customer would not
have a material adverse effect on the results of operations of the Company.
NOTE 10 COMMITMENTS AND CONTINGENCIES
The Company, as working interest owner, is responsible for payment of its
share of plugging and abandonment costs on its properties. As of December 31,
1997, the total estimate of these costs on the Company's oil and gas properties
was approximately $152.8 million, estimated to be incurred through the year
2007. The estimates of plugging and abandonment costs and their timing may
change due to many factors including, among others, actual production results,
inflation rates, and changes in environmental laws and regulations.
In August 1993, the Minerals Management Service (MMS) provided notice to
lessees of Outer Continental Shelf (OCS) leases that new levels of lease and
area wide bonds would be required effective November 26, 1993, in connection
with the plugging and abandoning of wells located offshore and the removal of
all production facilities. The coverage is designed to reflect an appropriate
balance between encouraging the maximum economic recovery of oil and natural gas
from federal offshore leases while providing the federal government an adequate
level of protection in the event the lessee defaults on its obligations to
properly abandon lease wells and remove platforms and other structures from the
property.
The MMS requires lessees of OCS properties to post bonds in connection with
the plugging and abandonment of wells located offshore and the removal of all
production facilities. Operators in the OCS waters of the Gulf of Mexico are
currently required to post area wide bonds of $3.0 million or $500,000 per
producing lease and supplemental bonds at the discretion of the MMS. On January
17, 1995, the Company entered into an agreement with Planet Indemnity Company
(Planet) whereby Planet agreed to issue $11.7 million of MMS surety bonds for
the Company and the Company agreed to post collateral for same in favor of
Planet. The collateral includes a mortgage on the Company's federal OCS leases
in the amount of $8.2 million, a letter of credit for $2.0 million and a pledge
of certain rights to escrowed funds. The Company has posted with the MMS an area
wide bond of $3.0 million and supplemental bonds totaling $17.1 million.
Pursuant to a schedule previously imposed by the MMS, the Company will be
required to post additional supplemental bonds up to a level of $24.6 million by
January 1999, unless the Company is determined by the MMS to be exempt from such
requirement due to certain financial tests. In addition, the Company is
currently working with the MMS to determine the level of supplemental bonding
(and the timing thereof) which will be required for some of the recently
acquired Central Gulf Properties. The Company does not anticipate that the cost
of any such bonding requirements will materially affect the Company's financial
position. Under certain circumstances, the MMS may require any Company
operations on federal leases to be suspended or terminated. Any such suspensions
or terminations could have a material adverse effect on the Company's financial
condition and operations. The MMS also intends to adopt financial responsibility
regulations under the Oil Pollution Act of 1990 (the OPA). The OPA regulations
impose a variety of regulations on "responsible parties" related to the
prevention of oil spills and liability for damages resulting from such spills in
United States waters. A "responsible party" includes the owner or operator of a
facility or vessel, or the lessee or permittee of an area in which an offshore
facility is located. The OPA assigns liability to each responsible party for oil
removal costs and a variety of public and private damages. While liability
limits apply in some circumstances, a party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Few defenses exist to the
liability imposed by the OPA.
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The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. For tank vessels, including mobile offshore drilling rigs, the OPA
imposes on owners, operators and charterers of the vessels, an obligation to
maintain evidence of financial responsibility of up to $10.0 million depending
on gross tonnage. With respect to offshore facilities, proof of greater levels
of financial responsibility may be applicable. This amount is subject to upward
regulatory adjustment up to $150.0 million.
In 1996, Statement of Position 96-1 ("SOP 96-1"), Environmental Remediation
Liabilities, was issued. The Company adopted SOP 96-1 in 1997. The adoption of
SOP 96-1 did not have a material effect on its results of operations or
financial position.
The Company has entered into operating leases for office space and
equipment for which $3.1 million, $1.9 million, $2.1 million, $1.7 million and
$1.2 million, in rental expense has been included in the accompanying financial
statements for the years ended December 31, 1997, 1996, 1995, 1994 and 1993,
respectively. Future minimum rental payments required for the years ending
December 31, 1998 through 2002 are $1.8 million, $1.7 million, $1.4 million,
$1.4 million and $1.3 million, respectively.
Resources has an agreement with Nova Corporation, a natural gas pipeline
company, to transport specified quantities of natural gas. Future minimum
transportation expense payments required for years ending December 31, 1998
through 2002 are $251,000, $157,000, $55,000, $55,000 and $55,000, respectively.
The Company has entered into agreements for transportation of natural gas
across Canada for sales to the Great Lakes region for up to 35 MMCFD expiring at
various dates through 2002 and 8 MMCFD expiring in 2007. Future minimum
transportation expense payments required for years ending December 31, 1998
through 2002 are $5.0 million, $3.1 million, $3.1 million, $3.1 million and $2.9
million, respectively.
NOTE 11 RELATED PARTY TRANSACTIONS
The Company currently conducts a portion of its oil and gas activities in
conjunction with a group of institutional and corporate investors that
participate in certain of the Company's acquisition, development and exploration
programs, and provide the Company with certain carried interests and management
fees. Management fee income of $3.0 million, $1.8 million, $1.3 million and $0.5
million, related to the years ended December 31, 1997, 1996, 1995 and the period
September 19, 1994 through year-end, respectively, is included on the
Supplemental Consolidated Statement of Income.
During 1997, 1996, 1995, 1994 and 1993, the Company paid $1.5 million, $1.4
million, $1.0 million, $0.6 million and $0.5 million, respectively, to an
affiliate of a stockholder associated with an overriding royalty interest owned
by it. In addition, during 1995 and 1994, the Company paid $4,753 and $124,376,
respectively, with respect to oil and gas properties previously operated by the
affiliate. These amounts are included in accounts receivable from stockholders
at December 31, 1995 and 1994.
OEI and a company controlled by a former director of UMC are each 40%
owners of Energy Arrow Exploration L.L.C. (Arrow). Total OEI payments to Arrow
in 1997, 1996, 1995 and 1994 were $82,000, $5,309,000, $2,477,000 and $301,000,
respectively, most of which related to lease acquisitions, seismic and drilling
costs.
In 1996, the Company executed agreements with various entities controlled
by two former directors of UMC covering co-ventures in Pakistan, Bangladesh and
possible other international exploration opportunities.
Effective November 1, 1995, the Company entered into a consulting agreement
for geological services with a party related to an officer of the Company. The
original term of this agreement expired on October 31, 1997, and the term has
been extended such that the new expiration date of the agreement is October 31,
1998. In 1995, the Company paid $50,000 for services rendered in connection with
an oil and gas prospect assigned to it by such party. In 1997 and 1996, the
Company paid $107,952 and $110,565, respectively, relating to the agreement.
During 1994, the Company obtained a loan from Union Planters Bank in
connection with the purchase of a seaplane. During 1995, Mr. Flores, Chairman of
the Board of OEI, was named a member of the Board of Directors of that bank. The
loan was made to the Company for the amount of $132,500, bearing interest at the
Wall Street Prime rate. On February 10, 1997, the balance of the loan, including
accrued interest, was paid in full. In addition, Union Planters Bank is a member
of the syndicate under the Revolving Credit Facility. Effective December 31,
1996, Mr. Flores resigned as a member of the Board of Directors of Union
Planters Bank.
Effective July 1, 1994, the Company acquired indirectly from stockholders
various overriding royalty interests for $1.2 million.
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In July 1994, the Company purchased a portion of the overriding royalty
interests previously assigned to an affiliate of a stockholder for $3.0 million.
At that time, two stockholders loaned the Company $5.0 million to make a payment
to a former stockholder. In September 1994, the stockholder affiliate exercised
its right to repurchase the overriding royalty interest from the Company for
$3.0 million and the Company repaid $3.0 million of the loans by the
stockholders. The Company utilized a portion of the net proceeds of the Ocean
Initial Offerings to repay the remaining $2.0 million in loans to stockholders.
During 1993, the Company loaned a total of $1,250,000 to three
stockholders. The loans were represented by promissory notes which bore interest
at 8% per annum and were due upon demand, and if no demand, then by December 31,
1994. During 1994, the Company forgave $500,000 due from each of two
stockholders. On March 1, 1995, $250,000 due from a former stockholder was
received.
During 1993 and 1994, the Company contracted with oilfield service
companies previously owned by current and former stockholders. The total amounts
paid for these services were $0.3 million during 1993 and $1.1 million during
the first six months of 1994 (at June 30, 1994, the stockholders assigned their
interest in such companies to a former stockholder). The Company believes that
the cost of such services would have been substantially similar to costs that
would have been charged by unaffiliated third parties for such services.
Prior to joining the Company in 1993, an officer of the Company and an
entity affiliated with him (collectively the "officer"), provided geological
consulting services for the Company. The Company paid approximately $106,000 to
the officer for services rendered in 1993 in connection with the acquisition of
the East Bay Complex. During 1994, the Company was assigned an oil and gas
prospect from the officer, who retained an overriding royalty interest. In
addition, the Company paid the officer $50,000 for services rendered in
connection therewith as well as $108,000 to a third party for acquisition of the
leases. During 1996, the Company purchased a working interest ownership in a
field where the Company had an existing interest from the officer for $0.2
million.
All transactions with the aforementioned entities are under normal industry
terms and conditions.
NOTE 12 LITIGATION AND CLAIMS
On December 29, 1997, a class action complaint (Newman v. Carson, et al.,
Civil Action No. 16109-NC) was filed in the Court of Chancery of the State of
Delaware, by a person claiming to represent the stockholders of UMC against UMC
and each of its directors. On January 9, 1998, a similar class action complaint
(Ross v. Brock. et al., Civil Action No. 98-00845) was filed in the District
Court of Harris County, Texas, 164th Judicial District by another person
claiming to represent the stockholders of UMC against UMC and each of its
directors. Preliminary settlements have been reached in each of these
complaints, the effects of which are not material to the supplemental
consolidated financial statements.
The U.S. Environmental Protection Agency has indicated that the Company may
be potentially responsible for costs and liabilities associated with alleged
releases of hazardous substances at two sites in Louisiana under the
Comprehensive Environmental Response, Compensation and Liability Act. Given the
extremely large number of companies that have been identified as potentially
responsible for releases of hazardous substances at the sites and the small
volume of hazardous substances allegedly disposed of by the companies whose
properties the Company acquired, management believes that the Company's
potential liability arising from these sites, if any, will not have a material
adverse impact on the Company.
In February 1998, the Tulane Environmental Law Clinic (Clinic), claiming to
represent several southeastern Louisiana environmental groups, gave notice that
it intends to file a Clean Water Act citizens' suit against the Company after a
sixty-day waiting period expires in connection with the discharge of produced
water in East Bay. The Clinic claims that the Company is violating the Clean
Water Act by discharging produced water from its East Bay Central Facilities
into Southwest Pass, and has stated that it will seek an injunction to require
the Company to cease its discharge of produced water, and will seek civil
penalties and attorney's fees. If the Clinic were to successfully obtain an
injunction, certain production operations at the Company's East Bay Facilities
could be interrupted until favorable resolution of the issue in court or
accelerated completion of the Company's plan to reformat operations to provide
for alternative produced water disposal. The Company believes that its zero
discharge compliance plan, which permits the temporary continued discharge of
produced water into Southwest Pass through July 1, 1999, is completely lawful as
authorized by a Compliance Order issued by the Louisiana Department of
Environmental Quality, and intends to vigorously defend any such citizens' suit,
if filed. The Clinic has delivered similar notices to other Louisiana coastal
producers.
The Company is a named defendant in lawsuits and is a party in governmental
proceedings from time to time arising in the ordinary course of business. While
the outcome of such lawsuits or other proceedings against the Company cannot be
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predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial position or results of operations of
the Company.
NOTE 13 GAS CONTRACT SETTLEMENTS
From time to time, the Company has had disagreements with certain
purchasers of the Company's natural gas production concerning the contractual
obligations of such purchasers to take specified quantities of gas at contract
prices. In order to resolve such disagreements, the Company has entered into gas
contract settlements, wherein, for a nonrefundable cash payment, the Company has
released the purchaser from its contractual obligations and, in some cases, the
contract itself. During 1997, 1996, 1995, 1994 and 1993, contract settlements of
$0.1 million, $0.3 million, $1.9 million, $2.0 million and $0.1 million,
respectively, were included in Operating revenues in the Supplemental
Consolidated Statement of Income.
NOTE 14 CREDIT RISK AND PRICE PROTECTION AGREEMENTS
TRADE RECEIVABLES AND PAYABLES
Substantially all of the Company's accounts receivable at December 31,
1997, result from oil and gas sales and joint interest billings to other
companies in the oil and gas industry and institutional partners. This
concentration of customers and joint interest owners may impact the Company's
overall credit risk, either positively or negatively, in that these entities may
be similarly affected by industry-wide changes in economic or other conditions.
Receivables from oil and gas sales are generally not collateralized. Credit
losses incurred by the Company on receivables generally have not been
significant in prior years.
OIL AND GAS MARKET HEDGES
The Company's revenues are primarily the result of sales of its oil and
natural gas production. Market prices of oil and natural gas fluctuate and may
adversely affect operating results. To mitigate this risk, the Company has, from
time to time, entered into crude oil and natural gas price hedging contracts to
reduce its exposure to price reductions on its production. These transactions
have been entered into with major financial institutions, thereby minimizing
credit risk.
The Company engages in futures contracts with certain of its production
through master swap agreements (Swap Agreements). The Company considers these
futures contracts to be hedging activities and, as such, monthly settlements on
these contracts are reflected in oil and gas sales. In order to consider these
futures contracts as hedges, (i) the Company must designate the futures contract
as a hedge of future production and (ii) the contract must reduce the Company's
exposure to the risk of changes in prices. Changes in the market value of
futures contracts treated as hedges are not recognized in income until the
hedged item is also recognized in income. If the above criteria are not met, the
Company will record the market value of the contract at the end of each month
and recognize a related gain or loss. Proceeds received or paid relating to
terminated contracts or contracts that have been sold are amortized over the
original contract period and reflected in oil and gas sales. The Company enters
into hedging transactions for the purpose of securing a price for a portion of
future production that is acceptable at the time the transaction is entered
into. The primary objective of these activities is to protect against decreases
in price during the term of the hedge.
The Swap Agreements provide for separate contracts tied to the New York
Mercantile Exchange (NYMEX) light sweet crude oil and natural gas futures
contracts. The Company has contracts which contain specific contracted prices
(Swaps) that are settled monthly based on the differences between the contract
prices and the average NYMEX prices for each month applied to the related
contract volumes. To the extent the average NYMEX price exceeds the contract
price, the Company pays the spread, and to the extent the contract price exceeds
the average NYMEX price the Company receives the spread. Under the terms of the
Swap Agreements, each counterparty has extended the Company a $5 million line of
credit for use in conjunction with its hedging activities. As of December 31,
1997, the fair market value of all contracts covered by the Swap Agreements was
approximately $6.8 million.
As of December 31, 1997, after giving effect to three hedges that were
unwound in January 1998, the Company's open forward position on its outstanding
crude oil Swaps was 4,500 MBbls at an average price of $19.88 per Bbl for the
year ended December 31, 1998. The Company currently has no outstanding natural
gas Swaps.
At December 31, 1996, the Company had oil collar contracts on 200,000
barrels of oil per month for January 1997 through June 1997, with a "floor"
price of $21.00 and an average "cap" price of $24.69. The Company's hedging
agreements are generally settled on a monthly basis and specify the third-party
index to be the NYMEX futures contract prices for the applicable
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commodity, matching the appropriate basis risk. There was no deferred hedge
gain or loss for crude oil at year end 1996. No contracts were in place at
December 31, 1997.
The results of hedging included in natural gas and oil revenues were ($1.3)
million, ($22.6) million, $3.6 million, $1.4 million and ($0.2) million for the
years ended December 31, 1997, 1996, 1995, 1994 and 1993.
INTEREST RATE MARKET HEDGES
The Company's existing interest rate hedge contracts have been entered into
with major financial institutions, minimizing the credit risk associated with
these agreements. See Note 5 for further discussion of these contracts.
NOTE 15 FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist of cash and cash equivalents,
short-term trade receivables and payables, long-term debt, interest rate hedging
agreements and natural gas and crude oil hedging agreements. As of December 31,
1997, 1996, 1995, 1994 and 1993, the fair market values of the Company's
financial instruments are shown below:
CASH, TRADE RECEIVABLES AND PAYABLES: The carrying amount approximates fair
market value due to the highly liquid nature of these short-term instruments.
REVOLVING CREDIT FACILITY: As of December 31, 1997, 1996, 1995 and 1994,
the carrying amount of the Revolving Credit Facility approximates fair value due
to the nature of the facility, whereby the interest rates offered by the member
banks are floating rates which reflect market rates.
GLOBAL CREDIT FACILITY: As of December 31, 1997, 1996, 1995, 1994 and 1993,
the carrying amount of the Global Credit Facility approximates fair value due to
the nature of the facility, whereby the interest rates offered by the member
banks are floating rates which reflect market rates.
13 1/2% SENIOR NOTES: As of December 31, 1997, the carrying amount of the
13 1/2% Notes was $0.2 million and the fair value was $0.3 million. As of
December 31, 1996, 1995 and 1994, the carrying amount of the 13 1/2% Notes was
$125.0 million and the fair value was $149.4 million, $141.9 million and $125.3
million, respectively.
10 3/8% SENIOR SUBORDINATED NOTES: As of December 31, 1997, 1996 and 1995,
the carrying amount of the 10 3/8% Notes was $150.0 million and the fair value
was $164.3 million, $163.9 million and $150.0 million, respectively. The
carrying amount of the 10 3/8% Notes approximates fair value at December 31,
1995 due to the issuance on October 30, 1995.
9 3/4% SENIOR SUBORDINATED NOTES: As of December 31, 1997 and 1996, the
carrying amount of the 9 3/4% Notes was $159.2 million and $159.1 million,
respectively, and the fair value was $175.6 million and $168.7 million,
respectively.
8 7/8% SENIOR SUBORDINATED NOTES: As of December 31, 1997, the carrying
amount of the 8 7/8% Notes was $199.7 million and the fair value was $212.5
million.
INTEREST RATE HEDGING AGREEMENTS: The fair market value of the interest
rate swap contracts at December 31, 1997, 1996, 1995 and 1994 was ($0.3)
million, ($0.3) million, ($0.8) million and $4.4 million, respectively. The
estimates of fair market value were determined by the institutional holders of
the hedges.
NATURAL GAS AND CRUDE OIL HEDGING AGREEMENTS: The fair market value of the
natural gas and crude oil swap contracts at December 31, 1997, 1996, 1995 and
1994, was $6.8 million, ($5.5) million, ($1.8) million and ($0.5) million,
respectively.
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NOTE 16 GEOGRAPHIC DATA
The Company is an independent oil and gas company engaged in the
exploration, development, production and acquisition of oil and natural gas
properties. Information about the Company's operations by geographic area for
the years ended December 31, 1997, 1996, 1995, 1994 and 1993 is as follows (in
thousands):
EQUATORIAL
GUINEA
AND OTHER
UNITED STATES CANADA CoTE D'IVOIRE INTERNATIONAL TOTAL
------------- ---------- ------------- ------------- -----------
YEAR ENDED DECEMBER 31, 1997
Revenues ....................... $ 426,901 $ 18,629 $ 27,803 $ 78,861 $ 552,194
Depreciation, depletion
and amortization ............. $ 179,492 $ 7,642 $ 14,638 $ 46,651 $ 248,423
Operating profit ............... $ 111,514 $ 3,392 $ 7,564 $ 26,689 $ 149,159
Capital expenditures ........... $ 642,756 $ 27,832 $ 56,931 $ 131,168 $ 858,687
Identifiable assets ............ $ 1,563,384 $ 52,619 $ 4,684 $ 22,308 1,642,995
YEAR ENDED DECEMBER 31, 1996
Revenues ....................... $ 334,485 $ 17,238 $ 22,680 $ 21,431 $ 395,834
Depreciation, depletion
and amortization ............. $ 122,651 $ 4,910 $ 9,129 $ 10,953 $ 147,643
Operating profit ............... $ 102,309 $ 5,200 $ 8,181 $ 6,739 $ 122,429
Capital expenditures ........... $ 326,821 $ 8,254 $ 18,588 $ 88,046 $ 441,709
Identifiable assets ............ $ 1,035,540 $ 45,887 $ 14,459 $ 25,355 1,121,241
YEAR ENDED DECEMBER 31, 1995
Revenues ....................... $ 222,362 $ 16,736 $ 4,729 $ -- $ 243,827
Depreciation, depletion
and amortization ............. $ 90,762 $ 6,009 $ 2,403 $ 1,942 $ 101,116
Operating profit (loss) ........ $ 39,499 $ 3,137 $ (1,959) $ (1,973) $ 38,704
Capital expenditures ........... $ 154,316 $ 4,805 $ 45,812 $ 31,746 $ 236,679
Identifiable assets ............ $ 572,243 $ 59,989 $ 76,117 $ 16,111 $ 724,460
YEAR ENDED DECEMBER 31, 1994
Revenues ....................... $ 156,197 $ 16,428 $ -- $ (89) $ 172,536
Depreciation, depletion
and amortization ............. $ 83,611 $ 7,992 $ -- $ -- $ 91,603
Impairment of proved oil
and gas properties ........... $ 119,313 $ 31,521 $ -- $ -- $ 150,834
Operating profit (loss) ........ $ (130,444) $ (33,179) $ 703 $ 3,288 $ (159,632)
Capital expenditures ........... $ 290,739 $ 28,689 $ 8,497 $ 3,522 $ 331,447
Identifiable assets ............ $ 537,332 $ 61,983 $ 23,723 $ 4,654 $ 627,692
YEAR ENDED DECEMBER 31, 1993
Revenues ....................... $ 118,388 $ 10,342 $ -- $ -- $ 128,730
Depreciation, depletion
and amortization ............. $ 46,811 $ 4,373 $ -- $ -- $ 51,184
Operating profit ............... $ 14,839 $ 1,184 $ -- $ -- $ 16,023
Capital expenditures ........... $ 236,940 $ 60,249 $ 2,192 $ 1,965 $ 301,346
Identifiable assets ............ $ 362,850 $ 74,977 $ 2,192 $ 1,965 $ 441,984
NOTE 17 DISCLOSURE OF OIL AND GAS OPERATIONS (UNAUDITED)
PROVED RESERVES
Substantially all reserve estimates presented herein were prepared by
either Ryder Scott Company, Netherland, Sewell & Associates, Inc., or McDaniel
& Associates Consultants Ltd., independent petroleum engineers. The Company
cautions that there are many uncertainties inherent in estimating proved
reserve quantities, in projecting future production rates and in the timing of
future development expenditures. In addition, reserve estimates of new
discoveries are more imprecise than those of properties with a production
history. Accordingly, these estimates are subject to change as additional
information becomes available.
Proved oil and gas reserves are the estimated quantities of crude oil,
condensate, natural gas and natural gas liquids that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known
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reservoirs under existing economic and operating conditions. Proved developed
oil and gas reserves are those reserves expected to be recovered through
existing wells with existing equipment and operating methods.
Information presented for the Company's international locations relates to
contract interests held in multiple production sharing contracts between the
Company, its joint venture partners and the governments of Cote d'Ivoire and
Equatorial Guinea. The Company has no ownership interest in the oil and gas
reserves but does have the right to share revenues and/or production and is
entitled to recover most field and other operating costs. The reserve estimates
are subject to revision as prices fluctuate due to the cost recovery feature
under the production sharing contract.
Net quantities of proved reserves and proved developed reserves of crude
oil (including condensate and natural gas liquids) and natural gas, as well as
the changes in proved reserves during the periods indicated, are set forth in
the tables below:
UNITED COTE EQUATORIAL
STATES CANADA D'IVOIRE GUINEA TOTAL
--------- ---------- ---------- ---------- ----------
NATURAL GAS (MMCF)
PROVED:
December 31, 1992 .................................. 194,376 -- -- -- 194,376
Revisions of previous estimates ................... 19,638 (3,321) -- -- 16,317
Extensions, discoveries and other additions ....... 21,570 6,527 -- -- 28,097
Purchases ......................................... 147,177 63,669 -- -- 210,846
Sales of reserves-in-place ........................ (22,594) -- -- -- (22,594)
Production (sold by the Company) .................. (28,490) (2,823) -- -- (31,313)
Production (consumed by the Company) .............. (2,162) -- -- -- (2,162)
--------- ---------- ---------- ---------- ----------
December 31, 1993 .................................. 329,515 64,052 -- -- 393,567
Revisions of previous estimates ................... 6,831 (6,310) -- -- 521
Extensions, discoveries and other additions ....... 19,731 76 32,612 -- 52,419
Purchases ......................................... 111,640 14,508 -- -- 126,148
Sales of reserves-in-place ........................ (3,546) (4) -- -- (3,550)
Production (sold by the Company) .................. (38,638) (4,487) -- -- (43,125)
Production (consumed by the Company) .............. (3,220) -- -- -- (3,220)
--------- ---------- ---------- ---------- ----------
December 31, 1994 .................................. 422,313 67,835 32,612 -- 522,760
Revisions of previous estimates ................... 13,748 (1,060) 5,746 -- 18,434
Extensions, discoveries and other additions ....... 46,205 2,060 58,290 -- 106,555
Purchases ......................................... 21,924 -- -- -- 21,924
Sales of reserves-in-place ........................ (68,113) (1,014) (13,995) (83,122)
Production (sold by the Company) .................. (51,271) (5,383) (192) -- (56,846)
Production (consumed by the Company) .............. (3,576) -- -- -- (3,576)
--------- ---------- ---------- ---------- ----------
December 31, 1995 .................................. 381,230 62,438 82,461 -- 526,129
Revisions of previous estimates ................... 43,640 (3,764) 7,848 -- 47,724
Extensions, discoveries and other additions ....... 53,960 8,567 2,488 -- 65,015
Purchases ......................................... 53,040 894 -- -- 53,934
Sales of reserves-in-place ........................ (19,178) (15) -- -- (19,193)
Production (sold by the Company) .................. (66,439) (5,339) (2,387) -- (74,165)
Production (consumed by the Company) .............. (3,363) -- -- -- (3,363)
--------- ---------- ---------- ---------- ----------
December 31, 1996 .................................. 442,890 62,781 90,410 -- 596,081
Revisions of previous estimates ................... 38,557 533 14,174 -- 53,264
Extensions, discoveries and other additions ....... 110,547 21,102 3,370 -- 135,019
Purchases ......................................... 69,740 21,377 33,275 -- 124,392
Sales of reserves-in-place ........................ (12,474) (301) -- -- (12,775)
Production (sold by the Company) ................. (81,154) (7,630) (4,939) -- (93,723)
Production (consumed by the Company) .............. (4,323) -- -- -- (4,323)
--------- ---------- ---------- ---------- ----------
December 31, 1997 ................................... 563,783 97,862 136,290 -- 797,935
========= ========== ========== ========== ==========
PROVED DEVELOPED:
December 31, 1993 .................................. 257,827 59,187 -- -- 317,014
========= ========== ========== ========== ==========
December 31, 1994 .................................. 333,367 66,997 -- -- 400,364
========= ========== ========== ========== ==========
December 31, 1995 .................................. 330,118 62,438 21,722 -- 414,278
========= ========== ========== ========== ==========
December 31, 1996 .................................. 355,421 62,781 21,433 -- 439,635
========= ========== ========== ========== ==========
December 31, 1997 .................................. 446,472 97,862 40,313 -- 584,647
========= ========== ========== ========== ==========
32
34
UNITED COTE EQUATORIAL
STATES CANADA D'IVOIRE GUINEA TOTAL
---------- ---------- ---------- ---------- ----------
CRUDE OIL (MBO)
PROVED:
December 31, 1992 ................................ 14,838 -- -- -- 14, 838
Revisions of previous estimates ................ (5,898) (229) -- -- (6,127)
Extensions, discoveries and other additions .... 200 875 -- -- 1,075
Purchases ...................................... 28,985 5,270 -- -- 34,255
Sales of reserves-in-place ..................... (9,541) -- -- -- (9,541)
Production ..................................... (2,454) (381) -- -- (2,835)
---------- ---------- ---------- ---------- ----------
December 31, 1993 ................................ 26,130 5,535 -- -- 31,665
Revisions of previous estimates ................ 2,588 (712) -- -- 1,876
Extensions, discoveries and other additions .... 950 391 4,626 -- 5,967
Purchases ...................................... 20,510 980 -- -- 21,490
Sales of reserves-in-place ..................... (725) (13) -- -- (738)
Production ..................................... (3,931) (618) -- -- (4,549)
---------- ---------- ---------- ---------- ----------
December 31, 1994 ................................ 45,522 5,563 4,626 -- 55,711
Revisions of previous estimates ................ 5,956 (201) 1,905 -- 7,660
Extensions, discoveries and other additions .... 2,441 151 1,440 5,258 9,290
Purchases ...................................... 5,102 -- -- -- 5,102
Sales of reserves-in-place ..................... (762) (82) (332) (1,502) (2,678)
Production ..................................... (7,883) (649) (285) -- (8,817)
---------- ---------- ---------- ---------- ----------
December 31, 1995 ................................ 50,376 4,782 7,354 3,756 66,268
Revisions of previous estimates ................ 5,351 (297) (2,538) 1,564 4,080
Extensions, discoveries and other additions .... 9,867 530 228 15,587 26,212
Purchases ...................................... 12,334 4 -- -- 12,338
Sales of reserves-in-place ..................... (1,040) (1,009) -- -- (2,049)
Production ..................................... (9,171) (511) (894) (967) (11,543)
---------- ---------- ---------- ---------- ----------
December 31, 1996 ................................ 67,717 3,499 4,150 19,940 95,306
Revisions of previous estimates ................ 403 192 854 441 1,890
Extensions, discoveries and other additions .... 16,809 181 218 24,086 41,294
Purchases ...................................... 17,344 45 1,062 -- 18,451
Sales of reserves-in-place ..................... (1,167) (95) -- -- (1,262)
Production ..................................... (12,158) (439) (1,027) (4,453) (18,077)
---------- ---------- ---------- ---------- ----------
December 31, 1997 ................................ 88,948 3,383 5,257 40,014 137,602
========== ========== ========== ========== ==========
PROVED DEVELOPED:
December 31, 1993 ................................ 22,226 5,458 -- -- 27,684
========== ========== ========== ========== ==========
December 31, 1994 ................................ 41,197 5,531 -- -- 46,728
========== ========== ========== ========== ==========
December 31, 1995 ................................ 46,669 4,735 3,302 -- 54,706
========== ========== ========== ========== ==========
December 31, 1996 ................................ 53,148 3,499 1,926 4,353 62,926
========== ========== ========== ========== ==========
December 31, 1997 ................................ 70,632 3,383 1,861 11,482 87,358
========== ========== ========== ========== ==========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The following table sets forth the standardized measure of the discounted
future net cash flows attributable to the Company's proved oil and gas reserves.
Future cash inflows were computed by applying year-end prices of oil and gas to
the estimated future production of proved oil and gas reserves. Gas prices were
escalated only where existing contracts contained fixed and determinable
escalation clauses. Contractually provided gas prices in excess of estimated
market clearing prices were used in computing the future cash inflows only if
the Company expects to continue to receive higher prices under legally
enforceable contract terms. Future prices actually received may differ from the
estimates in the standardized measure.
Future production and development costs represent the estimated future
expenditures (based on current costs) to be incurred in developing and producing
the proved reserves, assuming continuation of existing economic conditions.
Future income tax expenses were computed by applying statutory income tax rates
to the difference between pre-tax net cash flows relating to the Company's
proved oil and gas reserves and the tax basis of proved oil and gas properties.
In addition, the effects of statutory depletion in excess of tax basis,
available net operating loss carryforwards and investment tax credit
carryforwards were used in computing future income tax expense. The resulting
annual net cash inflows were then discounted using a 10% annual rate (in
thousands):
33
35
UNITED COTE EQUATORIAL
STATES CANADA D'IVOIRE GUINEA TOTAL(1)(2)
------------ ------------ ------------ ------------ ------------
AT DECEMBER 31, 1993
Future cash inflows ......................... $ 1,065,770 $ 190,526 $ -- $ -- $ 1,256,296
------------ ------------ ------------ ------------ ------------
Future production, development and
abandonment costs ........................ 595,805 79,023 -- -- 674,828
Future income taxes ......................... 59,745 30,776 -- -- 90,521
------------ ------------ ------------ ------------ ------------
Total future costs ....................... 655,550 109,799 -- -- 765,349
------------ ------------ ------------ ------------ ------------
Future net cash inflows ..................... 410,220 80,727 -- -- 490,947
Discount at 10% per annum ................... (139,052) (38,170) -- -- (177,222)
------------ ------------ ------------ ------------ ------------
Standardized measure of discounted
future net cash flows .................... $ 271,168 $ 42,557 $ -- $ -- $ 313,725
============ ============ ============ ============ ============
AT DECEMBER 31, 1994
Future cash inflows ......................... $ 1,372,829 $ 167,486 $ 128,401 $ -- $ 1,668,716
------------ ------------ ------------ ------------ ------------
Future production, development and
abandonment costs ........................ 761,758 79,311 75,201 -- 916,270
Future income taxes ......................... 28,186 18,692 16,203 -- 63,081
------------ ------------ ------------ ------------ ------------
Total future costs ....................... 789,944 98,003 91,404 -- 979,351
------------ ------------ ------------ ------------ ------------
Future net cash inflows ..................... 582,885 69,483 36,997 -- 689,365
Discount at 10% per annum ................... (177,604) (24,872) (18,601) -- (221,077)
------------ ------------ ------------ ------------ ------------
Standardized measure of discounted
future net cash flows .................... $ 405,281 $ 44,611 $ 18,396 $ -- $ 468,288
============ ============ ============ ============ ============
AT DECEMBER 31, 1995
Future cash inflows ......................... $ 1,583,610 $ 157,548 $ 317,580 $ 65,789 $ 2,124,527
------------ ------------ ------------ ------------ ------------
Future production, development and
abandonment costs ........................ 787,230 71,196 162,845 42,875 1,064,146
Future income taxes ......................... 87,285 19,448 37,232 7,562 151,527
------------ ------------ ------------ ------------ ------------
Total future costs ....................... 874,515 90,644 200,077 50,437 1,215,673
------------ ------------ ------------ ------------ ------------
Future net cash inflows ..................... 709,095 66,904 117,503 15,352 908,854
Discount at 10% per annum ................... (172,229) (24,011) (43,215) (1,458) (240,913)
------------ ------------ ------------ ------------ ------------
Standardized measure of discounted
future net cash flows .................... $ 536,866 $ 42,893 $ 74,288 $ 13,894 $ 667,941
============ ============ ============ ============ ============
AT DECEMBER 31, 1996
Future cash inflows ......................... $ 3,235,416 $ 206,041 $ 305,988 $ 450,785 $ 4,198,230
------------ ------------ ------------ ------------ ------------
Future production, development and
abandonment costs ........................ 1,339,933 60,494 128,884 255,055 1,784,366
Future income taxes ......................... 425,786 44,263 45,833 49,782 565,664
------------ ------------ ------------ ------------ ------------
Total future costs ....................... 1,765,719 104,757 174,717 304,837 2,350,030
------------ ------------ ------------ ------------ ------------
Future net cash inflows ..................... 1,469,697 101,284 131,271 145,948 1,848,200
Discount at 10% per annum ................... (397,980) (42,431) (40,465) (40,810) (521,686)
------------ ------------ ------------ ------------ ------------
Standardized measure of discounted
future net cash flows .................... $ 1,071,717 $ 58,853 $ 90,806 $ 105,138 $ 1,326,514
============ ============ ============ ============ ============
AT DECEMBER 31, 1997
Future cash inflows ....................... $ 2,765,682 $ 178,899 $ 384,217 $ 573,360 $ 3,902,158
------------ ------------ ------------ ------------ ------------
Future production, development and
abandonment costs ...................... 1,361,424 60,612 195,764 351,572 1,969,372
Future income taxes ....................... 188,623 26,464 41,001 37,417 293,505
------------ ------------ ------------ ------------ ------------
Total future costs ..................... 1,550,047 87,076 236,765 388,989 2,262,877
------------ ------------ ------------ ------------ ------------
Future net cash inflows ................... 1,215,635 91,823 147,452 184,371 1,639,281
Discount at 10% per annum ................. (274,783) (35,489) (58,883) (49,719) (418,874)
------------ ------------ ------------ ------------ ------------
Standardized measure of discounted
future net cash flows .................. $ 940,852 $ 56,334 $ 88,569 $ 134,652 $ 1,220,407
============ ============ ============ ============ ============
(1) Total future net cash flows before income taxes are $1,933,000,
$2,414,000, $1,060,000, $752,000 and $581,000 as of December 31, 1997,
1996, 1995, 1994 and 1993, respectively.
(2) Total future net cash flows before income taxes discounted at 10% per annum
are $1,343,000, $1,660,000, $740,000, $493,000 and $503,000 as of December
31, 1997, 1996, 1995, 1994 and 1993, respectively.
34
36
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):
1997 1996 1995 1994 1993
----------- ----------- ----------- ----------- -----------
Beginning balance .................................... $ 1,326,514 $ 667,941 $ 468,288 $ 313,725 $ 195,711
----------- ----------- ----------- ----------- -----------
Revisions to reserves proved in prior years -
Net changes in prices and production costs ........... (793,915) 547,292 120,429 (81,388) (40,517)
Net changes due to revisions in
quantity estimates ................................... 72,113 142,229 71,118 5,366 (32,855)
Net changes in estimated future development costs .... 75,484 19,698 78,953 7,901 19,857
Accretion of discount ................................ 149,599 70,889 49,721 34,709 28,686
Changes in production rates (timing) and other ....... (106,198) (113,080) (57,396) (17,453) (18,932)
----------- ----------- ----------- ----------- -----------
Total revisions .................................. (602,917) 667,028 262,825 (50,865) (43,761)
New field discoveries and extensions, net of future
production and development costs ..................... 558,737 437,284 140,072 54,271 26,237
Purchases of reserves in-place ......................... 180,707 153,155 41,824 236,644 322,495
Sale of reserves in-place .............................. (28,976) (23,569) (46,410) (5,458) (124,024)
Sales of oil and gas produced, net of
production costs ..................................... (424,286) (314,592) (157,842) (78,180) (63,287)
Net change in income taxes ............................. 210,628 (260,733) (40,816) (1,849) 354
----------- ----------- ----------- ----------- -----------
Net change in standardized measure of discounted
future net cash flows .............................. (106,107) 658,573 199,653 154,563 118,014
----------- ----------- ----------- ----------- -----------
Ending balance ......................................... 1,220,407 1,326,514 $ 667,941 $ 468,288 $ 313,725
=========== =========== =========== =========== ===========
35
37
SUPPLEMENTAL OIL AND GAS DISCLOSURES (IN THOUSANDS)
The following table sets forth revenue and direct cost, excluding interest
expense, general and administrative expense and other items, information
relating to the Company's oil and gas exploration and production activities.
The Company has no long-term supply or purchase agreements with governments or
authorities in which it acts as producer.
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
UNITED STATES
Oil and gas revenues ....................... $ 423,935 $ 333,255 $ 219,512 $ 153,375 $ 117,474
--------- --------- --------- --------- ---------
Operating costs:
Production cost ............................ 107,191 84,088 74,074 62,046 46,308
Depreciation, depletion and amortization ... 179,492 122,651 90,762 83,611 46,811
Impairment of oil and gas property ......... -- -- -- 119,313 --
Income tax provision (benefit) ............. 52,156 48,076 20,777 (42,406) 9,255
--------- --------- --------- --------- ---------
338,839 254,815 185,613 222,564 102,374
--------- --------- --------- --------- ---------
Results of operations .................... $ 85,096 $ 78,440 $ 33,899 $ (69,189) $ 15,100
========= ========= ========= ========= =========
COTE D'IVOIRE
Oil and gas revenues ....................... $ 27,803 $ 22,680 $ 4,729 $ -- $ --
--------- --------- --------- --------- ---------
Operating costs:
Production cost ............................ 5,602 5,370 3,388 -- --
Depreciation, depletion and amortization ... 14,638 9,129 2,403 -- --
Income tax provision (benefit) ............. 2,874 3,109 (404) -- --
--------- --------- --------- --------- ---------
23,114 17,608 5,387 -- --
--------- --------- --------- --------- ---------
Results of operations .................... $ 4,689 $ 5,072 $ (658) $ -- $ --
========= ========= ========= ========= =========
EQUATORIAL GUINEA AND OTHER FOREIGN
Oil and gas revenues ....................... $ 78,861 $ 21,430 $ -- $ -- $ --
--------- --------- --------- --------- ---------
Operating costs:
Production cost ............................ 5,520 3,738 -- -- --
Depreciation, depletion and amortization ... 46,651 10,953 1,942 -- --
Income tax provision (benefit) ............. 10,142 2,561 (738) -- --
--------- --------- --------- --------- ---------
62,313 17,252 1,204 -- --
--------- --------- --------- --------- ---------
Results of operations .................... $ 16,548 $ 4,178 $ (1,204) $ -- $ --
========= ========= ========= ========= =========
CANADA
Oil and gas revenues ....................... $ 18,595 $ 17,615 $ 17,080 $ 16,457 $ 10,342
--------- --------- --------- --------- ---------
Operating costs:
Production cost ............................ 6,081 5,200 5,475 5,216 3,432
Depreciation, depletion and amortization ... 7,642 4,910 6,009 7,992 4,373
Impairment of oil and gas property ......... -- -- -- 31,521 --
Income tax provision (benefit) ............. 1,851 2,852 2,126 (10,743) 964
--------- --------- --------- --------- ---------
15,574 12,962 13,610 33,986 8,769
--------- --------- --------- --------- ---------
Results of operations .................... $ 3,021 $ 4,653 $ 3,470 $ (17,529) $ 1,573
========= ========= ========= ========= =========
TOTAL
Oil and gas revenues ....................... $ 549,194 $ 394,980 $ 241,321 $ 169,832 $ 127,816
--------- --------- --------- --------- ---------
Operating costs:
Production cost ............................ 124,394 98,396 82,937 67,262 49,740
Depreciation, depletion and amortization ... 248,423 147,643 101,116 91,603 51,184
Impairment of oil and gas property ......... -- -- -- 150,834 --
Income tax provision (benefit) ............. 67,023 56,598 21,762 (53,149) 10,219
--------- --------- --------- --------- ---------
439,840 302,637 205,815 256,550 111,143
--------- --------- --------- --------- ---------
Results of operations .................... $ 109,354 $ 92,343 $ 35,506 $ (86,718) $ 16,673
========= ========= ========= ========= =========
36
38
NOTE 18 SUPPLEMENTAL GUARANTOR INFORMATION
Ocean Louisiana, the Company's only direct subsidiary, has unconditionally
guaranteed the full and prompt performance of the Company's obligations under
the 10 3/8% Notes, the 13 1/2%, the 9 3/4% Notes and the 8 7/8% Notes and
related indentures, including the payment of principal, premium (if any) and
interest. None of the referenced indentures place significant restrictions on a
wholly-owned subsidiaries' ability to make distributions to the parent. Other
than intercompany arrangements and transactions, the consolidated financial
statements of Ocean Louisiana are equivalent in all material respects to those
of the Company and therefore the separate consolidated financial statements of
Ocean Louisiana are not material to investors and have not been included herein.
However, in an effort to provide meaningful financial data relating to the
guarantor (i.e., Ocean Louisiana on an unconsolidated basis), the following
condensed consolidating financial information has been provided following the
policies set forth below:
(1) Investments in subsidiaries are accounted for by the Company on the
cost basis. Earnings of subsidiaries are therefore not reflected in
the related investment accounts.
(2) Certain reclassifications were made to conform all of the financial
information to the financial presentation on a consolidated basis.
The principal eliminating entries eliminate investments in
subsidiaries and intercompany balances.
Certain intercompany notes and the related accrued interest were
transferred from the Company to a newly formed non-guarantor subsidiary
effective as of January 1, 1997.
37
39
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF INCOME
For the years ended December 31, 1997, 1996, 1995, 1994 and 1993
(In thousands)
Unconsolidated
-----------------------------------------------
Non-
Guarantor Guarantor Consolidated
1997 OEI Subsidiary Subsidiary OEI
- ---- --------- --------- --------- ------------
Revenues .......................................... $ -- $ 428,432 $ 123,762 $ 552,194
--------- --------- --------- ---------
Costs and expenses:
Production costs ................................ -- 106,668 17,726 124,394
General and administrative ...................... 120 28,488 1,610 30,218
Depreciation, depletion and amortization ........ -- 178,582 69,841 248,423
--------- --------- --------- ---------
Income (loss) from operations ..................... (120) 114,694 34,585 149,159
Interest income (expense), net .................. (16,115) (65,670) 32,651 (49,134)
Other credits, net .............................. -- 2,753 434 3,187
--------- --------- --------- ---------
Income (loss) before income taxes ................. (16,235) 51,777 67,670 103,212
Income tax benefit (provision) .................... 20,585 (56,933) (4,644) (40,992)
Extraordinary item, net of taxes .................. -- (19,301) -- (19,301)
--------- --------- --------- ---------
Net income (loss) ................................. $ 4,350 $ (24,457) $ 63,026 $ 42,919
========= ========= ========= =========
1996
- ----
Revenues .......................................... $ -- $ 342,582 $ 53,252 $ 395,834
--------- --------- --------- ---------
Costs and expenses:
Production costs ................................ -- 84,030 14,366 98,396
General and administrative ...................... 180 25,193 1,993 27,366
Depreciation, depletion and amortization ........ -- 122,563 25,080 147,643
Impairment of proved oil and gas properties ..... -- -- -- --
--------- --------- --------- ---------
Income (loss) from operations ..................... (180) 110,796 11,813 122,429
Interest income (expense), net .................. 18,052 (50,021) (8,796) (40,765)
Other credits, net .............................. -- (639) 190 (449)
--------- --------- --------- ---------
Income (loss) before income taxes ................. 17,872 60,136 3,207 81,215
Income tax benefit (provision) .................... (6,208) (22,684) 2,677 (26,215)
--------- --------- --------- ---------
Net income ........................................ $ 11,664 $ 37,452 $ 5,884 $ 55,000
========= ========= ========= =========
1995
- ----
Revenues .......................................... $ -- $ 247,798 $ (3,971) $ 243,827
--------- --------- --------- ---------
Costs and expenses:
Production costs ................................ -- 74,074 8,863 82,937
General and administrative ...................... 415 17,611 3,044 21,070
Depreciation, depletion and amortization ........ -- 90,761 10,355 101,116
Impairment of proved oil and gas properties ..... -- -- -- --
--------- --------- --------- ---------
Income (loss) from operations ..................... (415) 65,352 (26,233) 38,704
Interest income (expense), net .................. 12,629 (43,409) (4,785) (35,565)
Other credits, net .............................. -- 274 403 677
--------- --------- --------- ---------
Income (loss) before income taxes ................. 12,214 22,217 (30,615) 3,816
Income tax benefit (provision) .................... (4,275) (9,185) 15,196 1,736
--------- --------- --------- ---------
Net income (loss) ................................. $ 7,939 $ 13,032 $ (15,419) $ 5,552
========= ========= ========= =========
38
40
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF INCOME
For the years ended December 31, 1997, 1996, 1995, 1994 and 1993, (continued)
(In thousands)
Unconsolidated
--------------------------------------------
Non-
Guarantor Guarantor Consolidated
1994 OEI Subsidiary Subsidiary OEI
- ---- ------------- -------------- ---------- -------------
Revenues . . . . . . . . . . . . . . . . . . . . . $ -- $ 155,689 $ 16,847 $ 172,536
------------ ------------- ------------ ------------
Costs and expenses:
Production costs . . . . . . . . . . . . . . . . -- 61,609 5,653 67,262
General and administrative . . . . . . . . . . . 801 16,715 4,953 22,469
Depreciation, depletion and amortization . . . . -- 82,294 9,309 91,603
Impairment . . . . . . . . . . . . . . . . . . . -- 119,313 31,521 150,834
------------ ------------- ------------ ------------
Income (loss) from operations . . . . . . . . . . . (801) (124,242) (34,589) (159,632)
Interest income (expense), net . . . . . . . . . 12,374 (23,037) (2,884) (13,547)
Other credits, net . . . . . . . . . . . . . . . -- (15,797) (277) (16,074)
------------ -------------- ------------- -------------
Income (loss) before income taxes . . . . . . . . . 11,573 (163,076) (37,750) (189,253)
Income tax benefit (provision) . . . . . . . . . . (6,921) 60,809 13,188 67,076
------------- ------------- ------------ ------------
Net income (loss) . . . . . . . . . . . . . . . . . $ 4,652 $ (102,267) $ (24,562) $ (122,177)
============ ============== ============= =============
1993
- ----
Revenues . . . . . . . . . . . . . . . . . . . . . $ -- $ 113,431 $ 15,299 $ 128,730
------------ ------------- ------------ ------------
Costs and expenses:
Production costs . . . . . . . . . . . . . . . . -- 45,135 4,605 49,740
General and administrative . . . . . . . . . . . 650 9,482 1,651 11,783
Depreciation, depletion and amortization . . . . -- 40,846 10,338 51,184
Impairment . . . . . . . . . . . . . . . . . . . -- 5,149 (5,149) --
------------ ------------- ------------- ------------
Income (loss) from operations . . . . . . . . . . . (650) 12,819 3,854 16,023
Interest income (expense), net . . . . . . . . . 10,238 (16,541) (1,284) (7,587)
Other credits, net . . . . . . . . . . . . . . . -- 2,179 95 2,274
------------ ------------- ------------ ------------
Income (loss) before income taxes . . . . . . . . . 9,588 (1,543) 2,665 10,710
Income tax benefit (provision) . . . . . . . . . . (404) 2,798 (1,582) 812
------------- ------------- ------------- ------------
Net income . . . . . . . . . . . . . . . . . . . . $ 9,184 $ 1,255 $ 1,083 $ 11,522
============ ============= ============ ============
39
41
SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 1997, 1996, 1995, 1994 and 1993
(In thousands)
Unconsolidated
--------------------------------------
Guarantor Non-Guarantor Eliminating Consolidated
OEI Subsidiary Subsidiaries Entries OEI
----------- ----------- ----------- ----------- -----------
1997
- ----
ASSETS
Current assets .......................... $ 11,480 $ 103,243 $ 56,649 $ (11,478) $ 159,894
Intercompany investments ................ 1,094,737 (19,479) 335,024 (1,410,282) --
Property and equipment, net ............. -- 1,033,193 390,644 -- 1,423,837
Other assets ............................ 5,395 89,189 (35,320) -- 59,264
----------- ----------- ----------- ----------- -----------
Total assets ....................... $ 1,111,612 $ 1,206,146 $ 746,997 $(1,421,760) $ 1,642,995
=========== =========== =========== =========== ===========
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities ..................... $ 14,804 $ 180,345 $ 37,208 $ (11,478) $ 220,879
Long-term debt .......................... 509,152 147,800 15,346 -- 672,298
Deferred credits and other liabilities .. -- 27,936 (3,455) -- 24,481
Stockholders' equity .................... 587,656 850,065 697,898 (1,410,282) 725,337
----------- ----------- ----------- ----------- -----------
Total liabilities & stockholders'
equity ......................... $ 1,111,612 $ 1,206,146 $ 746,997 $(1,421,760) $ 1,642,995
=========== =========== =========== =========== ===========
1996
- ----
ASSETS
Current assets .......................... $ 5,482 $ 178,219 $ 63,135 $ (5,479) $ 241,357
Intercompany investments ................ 1,004,867 (631,003) (182,827) (191,037) --
Property and equipment, net ............. -- 625,673 205,552 -- 831,225
Other assets ............................ 5,947 72,124 (29,412) -- 48,659
----------- ----------- ----------- ----------- -----------
Total assets ....................... $ 1,016,296 $ 245,013 $ 56,448 $ (196,516) $ 1,121,241
=========== =========== =========== =========== ===========
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities ..................... $ 8,806 $ 107,494 $ 52,488 $ (5,479) $ 163,309
Long-term debt .......................... 434,142 (5,700) 12,532 -- 440,974
Deferred credits and other liabilities .. -- 31,974 (8,088) -- 23,886
Stockholders' equity .................... 573,348 111,245 (484) (191,037) 493,072
----------- ----------- ----------- ----------- -----------
Total liabilities & stockholders' .. -- -- -- -- --
equity ......................... $ 1,016,296 $ 245,013 $ 56,448 $ (196,516) $ 1,121,241
=========== =========== =========== =========== ===========
1995
- ----
ASSETS
Current assets .......................... $ 1,437 $ 64,154 $ 31,383 $ (1,406) $ 95,568
Intercompany investments ................ 631,274 (364,072) (76,165) (191,037) --
Property and equipment, net ............. -- 467,015 107,061 -- 574,076
Other assets ............................ 6,103 61,594 (12,881) -- 54,816
----------- ----------- ----------- ----------- -----------
Total assets ....................... $ 638,814 $ 228,691 $ 49,398 $ (192,443) $ 724,460
=========== =========== =========== =========== ===========
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities ..................... $ 4,849 $ 80,839 $ 29,447 $ (1,406) $ 113,729
Long-term debt .......................... 275,000 85,917 55,574 -- 416,491
Deferred credits and other liabilities .. -- 27,480 (4,566) -- 22,914
Stockholders' equity .................... 358,965 34,455 (31,057) (191,037) 171,326
----------- ----------- ----------- ----------- -----------
Total liabilities & stockholders'
equity ......................... $ 638,814 $ 228,691 $ 49,398 $ (192,443) $ 724,460
=========== =========== =========== =========== ===========
40
42
SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEET December 31, 1997, 1996,
1995, 1994 and 1993 (continued) (In thousands)
UNCONSOLIDATED
----------------------------------------
GUARANTOR NON-GUARANTOR ELIMINATING CONSOLIDATED
1994 OEI SUBSIDIARY SUBSIDIARIES ENTRIES OEI
- ---- --------- ---------- ------------ --------- ---------
ASSETS
Current assets ................................ $ 1,101 $ 67,753 $ 13,139 $ (1,089) $ 80,904
Intercompany investments ...................... 444,175 (254,152) (12,831) (177,192) --
Property and equipment, net ................... -- 427,599 82,175 -- 509,774
Other assets .................................. 260 43,959 (7,205) -- 37,014
--------- --------- --------- --------- ---------
Total assets ............................ $ 445,536 $ 285,159 $ 75,278 $(178,281) $ 627,692
========= ========= ========= ========= =========
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities............................ $ 1,144 $ 66,282 $ 14,138 $ (1,089) $ 80,475
Long-term debt ................................ 125,000 247,289 21,384 -- 393,673
Deferred credits and other liabilities ........ (1,091) 6,188 21,819 -- 26,916
Stockholders' equity .......................... 320,483 (34,600) 17,937 (177,192) 126,628
--------- --------- --------- --------- ---------
Total liabilities & stockholders'
equity............................... $ 445,536 $ 285,159 $ 75,278 $(178,281) $ 627,692
========= ========= ========= ========= =========
1993
- ----
ASSETS
Current assets ................................ $ 17 $ 32,399 $ 6,248 $ -- $ 38,664
Intercompany investments ...................... 203,839 (114,323) (7,629) (81,887) --
Property and equipment, net ................... -- 270,185 93,034 -- 363,219
Other assets .................................. 1,964 38,137 -- -- 40,101
--------- --------- --------- --------- ---------
Total assets ............................ $ 205,820 $ 226,398 $ 91,653 $ (81,887) $ 441,984
========= ========= ========= ========= =========
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities............................ $ 5 $ 35,567 $ 11,031 $ -- $ 46,603
Long-term debt ................................ -- 93,098 12,499 -- 105,597
Deferred credits and other liabilities ........ (7) 117,209 19,239 -- 136,441
Stockholders' equity .......................... 205,822 (19,476) 48,884 (81,887) 153,343
--------- --------- --------- --------- ---------
Total liabilities & stockholders'
equity .............................. $ 205,820 $ 226,398 $ 91,653 $ (81,887) $ 441,984
========= ========= ========= ========= =========
41
43
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the years ended December 31, 1997, 1996, 1995, 1994 and 1993
(In thousands)
UNCONSOLIDATED
-----------------------------------------
GUARANTOR NON-GUARANTOR CONSOLIDATED
1997 OEI SUBSIDIARY SUBSIDIARIES OEI
- ---- --------- --------- ------------ ---------
Cash flows from operating activities:
Net income (loss) ........................................ $ 4,350 $ (24,457) $ 63,026 $ 42,919
Adjustments to reconcile net income
(loss) to cash from operating activities ................ (20,033) 218,926 73,175 272,068
Changes in assets and liabilities ........................ (1) 44,684 (19,995) 24,688
--------- --------- --------- ---------
Net cash provided by (used in) operating activities ... (15,684) 239,153 116,206 339,675
Cash flows used in investing activities .................... -- (596,986) (206,693) (803,679)
Cash flows provided by financing activities ................ 15,683 312,968 86,341 414,992
--------- --------- --------- ---------
Net decrease in cash and cash equivalents .................. (1) (44,865) (4,146) (49,012)
Cash and cash equivalents at beginning of period ........... 3 47,518 13,180 60,701
--------- --------- --------- ---------
Cash and cash equivalents at end of period ................. $ 2 $ 2,653 $ 9,034 $ 11,689
========= ========= ========= =========
1996
- ----
Cash flows from operating activities:
Net income ............................................... $ 11,664 $ 37,452 $ 5,884 $ 55,000
Adjustments to reconcile net income
to cash from operating activities ....................... 6,746 135,850 31,651 174,247
Changes in assets and liabilities ........................ 40 (7,964) (12,010) (19,934)
--------- --------- --------- ---------
Net cash provided by operating activities ............. 18,450 165,338 25,525 209,313
Cash flows used in investing activities .................... -- (353,650) (74,357) (428,007)
Cash flows provided by (used in) financing activities ...... (18,478) 228,987 55,088 265,597
--------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents ....... (28) 40,675 6,256 46,903
Cash and cash equivalents at beginning of period ........... 31 6,843 6,924 13,798
--------- --------- --------- ---------
Cash and cash equivalents at end of period ................. $ 3 $ 47,518 $ 13,180 $ 60,701
========= ========= ========= =========
1995
- ----
Cash flows from operating activities:
Net income (loss) ........................................ $ 7,939 $ 13,032 $ (15,419) $ 5,552
Adjustments to reconcile net income
(loss) to cash from operating activities ................ 494 77,527 23,014 101,035
Changes in assets and liabilities ........................ 5,755 11,678 (18,707) (1,274)
--------- --------- --------- ---------
Net cash provided by (used in) operating activities ... 14,188 102,237 (11,112) 105,313
Cash flows used in investing activities .................... -- (96,004) (64,220) (160,224)
Cash flows provided by (used in) financing activities ...... (14,169) (3,686) 74,171 56,316
--------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents ....... 19 2,547 (1,161) 1,405
Cash and cash equivalents at beginning of period ........... 12 4,296 8,085 12,393
--------- --------- --------- ---------
Cash and cash equivalents at end of period ................. $ 31 $ 6,843 $ 6,924 $ 13,798
========= ========= ========= =========
42
44
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the years ended December 31, 1997, 1996, 1995, 1994 and 1993 (continued)
(In thousands)
GUARANTOR NON-GUARANTOR CONSOLIDATED
1994 OEI SUBSIDIARY SUBSIDIARIES OEI
- ----- --------- ---------- ------------- ---------
Cash flows from operating activities:
Net income (loss) ........................................ $ 4,652 $(102,267) $ (24,562) $(122,177)
Adjustments to reconcile net income
(loss) to cash from operating activities ................ 880 13,415 29,248 43,543
Changes in assets and liabilities ........................ (805) (9,984) 17,505 6,716
--------- --------- --------- ---------
Net cash provided by (used in) operating activities ... 4,727 (98,836) 22,191 (71,918)
Cash flows provided by (used in) investing activities ...... 340 (195,334) (31,729) (226,723)
Cash flows provided by (used in) financing activities ...... (5,072) 298,176 17,236 310,340
--------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents ....... (5) 4,006 7,698 11,699
Cash and cash equivalents at beginning of period ........... 17 290 387 694
--------- --------- --------- ---------
Cash and cash equivalents at end of period ................. $ 12 $ 4,296 $ 8,085 $ 12,393
========= ========= ========= =========
1993
- ----
Cash flows from operating activities:
Net income ............................................... $ 9,184 $ 1,255 $ 1,083 $ 11,522
Adjustments to reconcile net income
to cash from operating activities ....................... 382 99,780 27,556 127,718
Changes in assets and liabilities ........................ 45 (7,261) 14,211 6,995
--------- --------- --------- ---------
Net cash provided by operating activities ............. 9,611 93,774 42,850 146,235
Cash flows used in investing activities .................... -- (218,723) (55,558) (274,281)
Cash flows provided by (used in) financing activities ...... (9,617) 124,965 11,593 126,941
--------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents ....... (6) 16 (1,115) (1,105)
Cash and cash equivalents at beginning of period ........... 23 274 1,502 1,799
--------- --------- --------- ---------
Cash and cash equivalents at end of period ................. $ 17 $ 290 $ 387 $ 694
========= ========= ========= =========
43
45
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
On December 23, 1997, the Company announced that it entered into a Merger
Agreement with UMC that provided in part for a stock-for-stock merger of UMC
with and into the Company. Pursuant to the Merger Agreement, at the effective
time of the Merger, the Company's stockholders received 2.34 shares of the
combined company's common stock for each share of the Company's common stock
then owned and UMC stockholders received 1.30 shares of the combined company's
common stock for each share of UMC stock then owned. The Merger, completed on
March 27, 1998, was treated as pooling of interests for accounting purposes.
This financial review summarizes the combined financial condition and
results of operations giving retroactive effect to the Merger and should be read
in conjunction with the Company's supplemental consolidated financial statements
and the notes thereto included in this Form 8-K. The consolidated financial
statements previously filed in the Company's Form 10-K for the year ended
December 31, 1997, have been restated herein to reflect the combination of the
historical results of OEI and UMC in accordance with pooling of interests
accounting.
GENERAL
The Company is an independent energy company engaged in the exploration,
development, acquisition and production of crude oil and natural gas offshore
Gulf of Mexico, across North America and in the oil and gas producing regions of
Cote d'Ivoire, Equatorial Guinea, Pakistan and Bangladesh. As of December 31,
1997, the Company had estimated proved reserves of approximately 137.6 MMBbls of
oil and 797.9 Bcf of natural gas, or an aggregate of approximately 270.6 MMBOE,
with a present value of future net revenues before income taxes of approximately
$1.3 billion and a standardized measure of discounted future net cash flows of
approximately $1.2 billion. On a BOE basis, approximately 51% of the Company's
proved reserves at December 31, 1997 were oil.
44
46
The following table sets forth information with respect to the Company's
production and average unit prices and costs for the periods indicated:
YEARS ENDED
DECEMBER 31,
----------------------------------------
1997 1996 1995
---------- ---------- ----------
Production:
Oil (MBO)
United States .................................. 12,159 9,171 7,883
Canada ......................................... 439 511 649
Cote d'Ivoire .................................. 1,027 894 285
Equatorial Guinea .............................. 4,453 967 --
---------- ---------- ----------
Total ....................................... 18,078 11,543 8,817
========== ========== ==========
Natural gas (MMCF)
United States .................................. 81,154 66,439 51,271
Canada ......................................... 7,630 5,339 5,383
Cote d'Ivoire .................................. 4,939 2,387 192
---------- ---------- ----------
Total ....................................... 93,723 74,165 56,846
========== ========== ==========
Average net sales price, including hedging:
Oil ($ per bbl)
United States .................................. $ 18.87 $ 20.05 $ 17.14
Canada ......................................... $ 17.97 $ 19.43 $ 16.59
Cote d'Ivoire .................................. $ 18.35 $ 20.56 $ 15.45
Equatorial Guinea .............................. $ 17.71 $ 22.17 $ --
Average ..................................... $ 18.54 $ 20.24 $ 17.05
Natural gas ($ per MCF)
United States .................................. $ 2.40 $ 2.25 $ 1.65
Canada ......................................... $ 1.40 $ 1.44 $ 1.17
Cote d'Ivoire .................................. $ 1.81 $ 1.80 $ 1.72
Average ..................................... $ 2.28 $ 2.18 $ 1.60
Additional disclosures ($ per BOE):
Production and operating costs(1) ................. $ 3.02 $ 3.26 $ 3.55
Ad valorem and production taxes ................... $ 0.67 $ 0.86 $ 0.98
Oil and natural gas DD&A(2) ....................... $ 7.23 $ 6.06 $ 5.43
- ---------------------------------------------------------------
(1) Costs incurred to operate and maintain wells and related equipment,
excluding ad valorem and production taxes.
(2) Does not include depreciation and amortization of corporate assets.
45
47
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1996
Operating revenues. The Company's total operating revenues increased
approximately $156.4 million, or 40%, to $552.2 million for the year ended
December 31, 1997, from $395.8 million for the comparable period in 1996.
Production levels for the year ended December 31, 1997, increased 41% to 33,699
MBOE from 23,904 MBOE for the comparable period in 1996. The increase in oil and
gas revenues is due to increased oil volumes in the Gulf of Mexico and
Equatorial Guinea, resulting from a full year's production from the Central Gulf
Properties and Block B and higher U.S. gas volumes.
Oil revenues increased 43% to $335.1 million, the result of significantly
increased worldwide production volumes offset by a drop in the average realized
price received. Oil production increased 57% to 18,078 MBO in 1997 due primarily
to increased oil production in the Gulf of Mexico and Equatorial Guinea. The
average sales price before hedging for oil decreased 13% to $18.54 in 1997
compared to 1996.
Natural gas revenues increased 33% to $214.1 million, the result of slight
increases in natural gas prices and the impact of certain hedging activities,
offset by certain property sales. The average sales price before hedging for
natural gas remained constant at $2.30 per MCF in 1997 and 1996. Natural gas
production for 1997 was 93,723 MMCF, an increase of 26% over 1996 volumes due
primarily to acquisitions and increased production in the Gulf of Mexico, Cote
d'Ivoire and Canada, offset by property sales and natural production declines in
North America.
For the year ended December 31, 1997, the Company's total revenues were
further affected by a $1.3 million decrease in hedging revenues. In order to
manage its exposure to price risks in the sale of its crude oil and natural gas,
the Company from time to time enters into price hedging arrangements. The
Company's average sales prices including hedging for oil and natural gas for the
year ended December 31, 1997 were $18.54 per Bbl and $2.28 per Mcf compared with
$20.24 per Bbl and $2.18 per Mcf in the prior period.
Production costs. For the year ended December 31, 1997, total production
costs were $124.4 million, as compared to $98.4 million in the 1996 period, an
increase of 26%. This increase primarily results from fluctuations in normal
operating expenses, including operating expenses associated with increased
production from new facilities and an increase of approximately $11.8 million
relating to production costs of the Central Gulf Properties acquired in 1996.
Production and operating costs (costs incurred to operate and maintain wells and
related equipment, excluding ad valorem and production taxes) decreased to $3.02
per BOE for the year ended December 31, 1997, from $3.26 per BOE in the
comparable 1996 period. This decrease is primarily the result of increased
production in the Company's offshore Gulf of Mexico and Equatorial Guinea
fields, which have substantial fixed operating costs due to the capital
intensive nature of the facilities, further impacted by the under-utilization of
capacity in the Gulf of Mexico fields.
General and administrative expenses. For the year ended December 31, 1997,
general and administrative expenses were $30.2 million as compared to $27.4
million in the comparable 1996 period, an increase of 10%. This increase is
primarily due to costs of increased corporate staffing associated with both an
increase in drilling activities and the Company's acquisitions in 1996 and 1997.
In addition, a new systems implementation partially offset by an increase in
1997 in the capitalization of a portion of the salaries paid to employees
directly engaged in the acquisition, exploration and development of oil and gas
properties in accordance with the full cost method of accounting contributed to
the increase. General and administrative expenses per BOE decreased to $0.90 per
BOE for the year ended December 31, 1997, from $1.14 per BOE for the comparable
1996 period. This unit decrease is primarily the result of increased production
in the Company's Gulf of Mexico and Equatorial Guinea fields.
Depreciation, depletion and amortization expense. For the year ended
December 31, 1997, depreciation, depletion and amortization (DD&A) expense was
$248.4 million as compared to $147.6 million in the comparable 1996 period, an
increase of 68%. This variance can primarily be attributed to the Company's
increased production and related current and future capital costs from the 1996
and 1997 Gulf of Mexico and international drilling programs and acquisitions,
partially offset by the increase in proved reserves resulting from such programs
and acquisitions. On a BOE basis, oil and gas DD&A for the year ended December
31, 1997, was $7.23 per BOE as compared to $6.06 per BOE for the year ended
December 31, 1996. This unit decrease is primarily the result of increased
production in the Company's Gulf of Mexico and Equatorial Guinea fields.
Interest and debt expense. For the year ended December 31, 1997, interest
and debt expense increased 20% to $49.1 million, from $40.8 million in the
comparable 1996 period. This increase is primarily the result of an increase of
approximately $11.5 million from the comparable 1996 period relating to the
9 3/4% Notes issued in September 1996 and interest and debt expense of
approximately $8.9 million related to the issuance of $200 million of the
Company's 8 7/8% Senior Subordinated Notes due 2007
46
48
(8 7/8% Notes) in July 1997. In addition, interest and debt expense increased in
both periods due to a higher average balance on the Company's bank credit
facilities. The increase was partially offset by a decrease in interest expense
of approximately $7.0 million as a result of the Company's purchase of $124.8
million of the $125.0 million in original principal amount of the Company's 13
1/2% Senior Notes due 2004 (13 1/2% Notes) on July 22, 1997, and by an increase
in the amount of interest capitalized in the 1997 period resulting from an
increase in the Company's unevaluated assets, including additional acreage and
seismic data.
Income tax expense (benefit). An income tax provision of $41.0 million (of
which $6.2 million is a current provision and $34.8 million is a deferred
provision) was recognized for 1997, compared to a provision of $26.2 million (of
which $0.8 million was a current provision and $25.4 million was a deferred
provision) for 1996. A significant portion of current taxes in 1997 is a $4.6
million non-cash provision representing current taxes incurred in Cote d'Ivoire
which, under the terms of the production sharing contract, will be paid by the
Ivorian government from their production proceeds. Consistent with Statement of
Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes, the
deferred income tax provision was derived primarily from changes in deferred
income tax assets and liabilities recorded on the balance sheet. The 1996
deferred tax provision was affected by the use of $13.0 million of net operating
loss (NOL) carryforwards to essentially eliminate 1996 taxable income and the
deferred tax effect of exercised stock options. At December 31, 1997, the
Company had $122.7 million of United States (U.S.) NOL carryforwards, $67.0
million of Equatorial Guinea NOL carryforwards and $32.2 million of Canadian
federal tax pools. The Company paid cash income taxes in 1997 and 1996 of $1.8
million, and $0.4 million, respectively, to several states, Canada and the U.S.
Extraordinary loss on early extinguishment of debt. On July 22, 1997, the
Company purchased approximately $124.8 million of the $125.0 million original
principal amount of the 13 1/2% Notes for approximately $151.5 million. This
repurchase resulted in an after-tax extraordinary charge of $19.3 million,
representing the difference between the purchase price and the net carrying
value of the 13 1/2% Notes.
Net income. Due to the factors described above, net income before an
extraordinary charge for the year ended December 31, 1997, increased to $62.2
million, an increase of $7.2 million or 13% from net income of $55.0 million for
the comparable 1996 period. Including the effect of the extraordinary charge,
the Company recorded net income of $42.9 million for the year ended December 31,
1997.
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1996 AND 1995
Operating revenues. The Company's total operating revenues increased
approximately $152.0 million, or 62%, to $395.8 million for the year ended
December 31, 1996, from $243.8 million for the comparable period in 1995.
Production levels for the year ended December 31, 1996, increased 31% to 23,904
MBOE from 18,291 MBOE for the comparable period in 1995 resulting from the
Company's Gulf of Mexico activities and a full year of production in Cote
d'Ivoire.
Oil revenues increased 55% to $233.6 million, the result of increases in
both production volumes and realized prices received. Oil production increased
31% to 11,543 MBO in 1996 due to expansion of Gulf of Mexico operations,
acquisitions and a full year of production in Cote d'Ivoire. The average sales
price before hedging for oil increased 26% to $21.42 in 1996 compared to 1995.
Natural gas revenues increased 77% to $161.4 million, the result of strong
gas prices and increased production, offset somewhat by the impact of property
sales. The average sales price before hedging for gas was $2.30 per Mcf versus
$1.54 per Mcf in the prior period.
For the year ended December 31, 1996, the Company's total revenues were
further affected by a $22.6 million decrease in hedging revenues. This decrease
was the result of significant increases in product prices in 1996. In order to
manage its exposure to price risk in the sale of its crude oil and natural gas,
the Company from time to time enters into price hedging arrangements. The
Company's average sales prices including hedging for oil and natural gas for the
year ended December 31, 1996, were $20.24 per Bbl and $2.18 per Mcf compared
with $17.05 per Bbl and $1.60 per Mcf in the prior period.
Production costs. For the year ended December 31, 1996, total production
costs were $98.4 million, as compared to $82.9 million in the 1995 period, an
increase of 19%. This increase primarily results from fluctuations in normal
operating expenses, including operating expenses associated with increased
production, commencement of production in Equatorial Guinea and an increase of
approximately $2.8 million relating to production costs of the newly acquired
Central Gulf Properties. Production
47
49
and operating costs (costs incurred to operate and maintain wells and related
equipment, excluding ad valorem and production taxes) decreased to $3.26 per BOE
for the year ended December 31, 1996, from $3.55 per BOE in the comparable 1995
period. This decrease is primarily the result of increased production in the
Company's offshore oil and gas fields, which have substantial fixed operating
costs due to the capital intensive nature of the facilities and the
under-utilization of capacity.
General and administrative expenses. For the year ended December 31, 1996,
general and administrative expenses were $27.4 million as compared to $21.1
million in the comparable 1995 period. This increase is primarily due to costs
of increased corporate staffing associated with both an increase in
international drilling activities, the Company's acquisition of the Central Gulf
Properties and miscellaneous non-cash benefits accruals. This was partially
offset in the 1996 period by an increase in the capitalization of a portion of
the salaries paid to employees directly engaged in the acquisition, exploration
and development of oil and gas properties. General and administrative expense
per BOE decreased to $1.14 per BOE for the year ended December 31, 1996, from
$1.15 per BOE for the comparable 1995 period.
Depreciation, depletion, and amortization expense. For the year ended
December 31, 1996, DD&A expense was $147.6 million as compared to $101.1 million
in the comparable 1995 period, an increase of 46%. This variance can primarily
be attributed to the Company's increased production and related current and
future capital costs from the 1995 and 1996 worldwide drilling programs and
acquisitions partially offset by the increase to proved reserves resulting from
programs and acquisition. On a BOE basis, DD&A for the year ended December 31,
1996, was $6.06 per BOE as compared to $5.43 per BOE for the year ended December
31, 1995.
Interest and debt expense. For the year ended December 31, 1996, interest
and debt expense increased 15% to $40.8 million, from $35.6 million in the
comparable 1995 period. This increase is primarily a result of generally higher
debt levels partially offset by the repayment of a portion of the Company's debt
with proceeds from the public offerings of common stock in March and November
1996. The increase was also partially offset by increases in the amount of
interest capitalized in the 1996 period, as a result of an increase in the
Company's unevaluated assets, including additional acreage and seismic data.
Income tax expense (benefit). An income tax provision of $26.2 million was
recognized for 1996, compared to a benefit of $1.7 million for 1995. Consistent
with SFAS No. 109, the deferred income tax provision or benefit was derived
primarily from changes in deferred income tax assets and liabilities recorded on
the balance sheet. The primary items affecting the 1996 deferred tax provision
were the use of $13.0 million of NOL carryforwards to eliminate 1996 taxable
income and the deferred tax effect of exercised stock options. At December 31,
1996, the Company had $127.0 million of U.S. NOL carryforwards, $52.0 million of
Equatorial Guinea NOL carryforwards and $17.6 million of Canadian federal tax
pools. The Company paid cash income taxes in 1996 and 1995 of $0.4 million and
$0.6 million, respectively, to several states, Canada and the U.S. for the
Alternative Minimum Tax.
Net income. Due to the factors described above, net income for the year
ended December 31, 1996, increased to $55.0 million, an increase of $49.4
million or 882% from net income of $5.6 million for the comparable 1995 period.
LIQUIDITY AND CAPITAL RESOURCES
The following summary table reflects comparative cash flows for the Company
for the years ended December 31, 1997, 1996 and 1995:
YEAR ENDED DECEMBER 31,
----------------------------------
1997 1996 1995
---------- --------- --------
(IN THOUSANDS)
Net cash provided by operating activities $339,675 $209,313 $105,313
Net cash used in investing activities (803,679) (428,007) (160,224)
Net cash provided by financing activities 414,992 265,597 56,316
For the year ended December 31, 1997, net cash provided by operating
activities increased by $130.4 million, or 62%, as compared to the year ended
December 31, 1996. This increase related primarily to an increase in revenues,
partially offset by increases in lease operating expenses, severance taxes,
general and administrative expenses, interest expense, certain non-cash expenses
and the extraordinary loss related to the purchase of substantially all of the
13 1/2% Notes. In addition, timing differences with respect to payment on
certain receivable and payable balances at any period affect cash provided by
operating during each period.
48
50
Cash used in investing activities during the year ended December 31, 1997,
increased to $803.7 million as compared to $428.0 million in the comparable 1996
period. This increase relates primarily to the Company's active acquisition
programs, primarily in the Gulf of Mexico with the Main Pass and South Pass
acquisitions, active exploration program in the Gulf of Mexico and Equatorial
Guinea and development project expenditures, partially offset by net proceeds
from sales of property interests of $52.9 million.
Financing activities during the year ended December 31, 1997, generated
cash of $415.0 million, as compared to $265.6 million in the comparable 1996
period. On July 2, 1997, the Company completed the offering of its 8 7/8% Notes
at a discount for net proceeds (after offering costs) of $195.2 million, which
were used primarily to finance the purchase of substantially all of the 13 1/2%
Notes and to repay indebtedness under the Revolving Credit Facility. On November
18, 1997, the Company completed a public offering of 7.3 million shares of
common stock, resulting in net proceeds of $178.1 million, which were used to
repay outstanding indebtedness under the Revolving Credit Facility. The increase
in cash during the 1996 period was primarily a result of the completion of the
public offerings of common stock and the issuance of the 9 3/4% Notes, which
yielded net proceeds to the Company of $245.2 million and $154.0 million,
respectively.
Capital requirements. The Company's capital investments to date have
focused primarily on exploration, acquisitions and development of proved
properties. The Company's expenditures for property acquisition, exploration and
development for the years ended December 31, 1997, 1996 and 1995 are as follows:
YEAR ENDED DECEMBER 31,
--------------------------------------
1997 1996 1995
--------- --------- ---------
(IN THOUSANDS)
Property acquisition costs:
Proved ........................................... $ 130,074 $ 66,105 $ 25,819
Unproved ......................................... 107,817 75,365 5,724
Properties held for resale ........................... -- (37,200) --
Exploration costs .................................... 250,698 108,430 48,992
Development costs .................................... 317,975 211,068 144,534
Capitalized interest on unevaluated properties ....... 12,802 7,408 3,882
Capitalized general and administrative costs ......... 14,992 10,533 7,728
--------- --------- ---------
Total costs incurred ................................. $ 834,358 $ 441,709 $ 236,679
========= ========= =========
The Company makes, and will continue to make, substantial capital
expenditures for the acquisition, exploration, development, production and
abandonment of its oil and natural gas reserves. The Company has historically
funded its operations, acquisitions, exploration and development expenditures
from cash flows from operating activities, bank borrowings, sales of common and
preferred stock, issuance of senior subordinated notes, sales of non-strategic
oil and natural gas properties, sales of partial interests in exploration
concessions and project finance borrowings. The Company intends to finance 1998
capital expenditures related to this strategy primarily with funds provided by
operations, borrowings or other capital markets.
The Company is also a party to two escrow agreements that provide for the
future plugging and abandonment costs associated with oil and gas properties.
The first agreement, related to the East Bay Fields, requires monthly deposits
of $100,000 through June 30, 1998, and $350,000 thereafter until the balance in
the escrow account equals $40.0 million, unless the Company commits to the
plugging and abandonment of a certain number of wells in which case the increase
will be deferred. The second agreement, related to Main Pass 69, required an
initial deposit of $250,000 and monthly deposits thereafter of $50,000 until the
balance in the escrow account equals $7.5 million. As of December 31, 1997, the
escrow balances totaled $8.5 million.
The Company's capital expenditure budget for 1998 is expected to be
approximately $600.0 million. Primary areas of emphasis will be West Africa,
East Texas, the Gulf of Mexico and other international areas. In addition, the
Company will evaluate its level of capital spending throughout the year based
upon drilling results, commodity prices, cash flows from operations and property
acquisitions. Actual capital spending may vary from the capital expenditure
budget.
The Company continues to maintain a sound financial structure. The
Company's debt to total capitalization ratio has increased slightly to 48% at
December 31, 1997, from 47% at December 31, 1996. However, the Company's
interest coverage
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ratio (calculated as the ratio of income from operations plus DD&A and
impairment of proved oil and gas properties to interest plus capitalized
interest less non-cash amortization of debt issue costs) was 6.8 to 1 for 1997
compared with 6.5 to 1 for 1996. This measure provides investors with a measure
of the Company's ability to service debt. The high ratio in 1997 and improvement
over 1996 are indicators of the Company's strong financial position and future
capability to service debt and fund operations. Access to various capital
markets, combined with cash flows from operating activities, provide the Company
with the financial strength, leverage and liquidity that will allow it to fund
its 1998 capital expenditure program, including both Gulf of Mexico and
international exploration and development opportunities in Cote d'Ivoire,
Equatorial Guinea, Pakistan and Bangladesh, and continue to selectively pursue
strategic acquisitions.
Concurrent with the closing of the Merger on March 27, 1998, the Company
entered into a $750.0 million five-year unsecured revolving credit facility (OEI
Credit Facility) which combines and replaces the Revolving Credit Facility and
the Global Credit Facility. The OEI Credit Facility, which is with a group of
commercial banks, provides for various borrowing options under either a base
rate or Eurodollar margin rates. As of March 31, 1998, the new OEI Credit
Facility provides a $600.0 million initial borrowing base. As of March 31, 1998,
total borrowings outstanding against the facility were approximately $265.0
million, leaving approximately $335.0 million of available credit.
In addition to developing its existing reserves, the Company attempts to
increase its reserve base, production and operating cash flow by engaging in
strategic acquisitions of oil and gas properties. In order to finance other
possible future acquisitions, the Company may seek to obtain additional debt or
equity financing. The availability and attractiveness of these sources of
financing will depend upon a number of factors, some of which will relate to the
financial condition and performance of the Company, and some of which will be
beyond the Company's control, such as prevailing interest rates, oil and gas
prices and other market conditions. There can be no assurance that the Company
will acquire any additional producing properties. In addition, the ability of
the Company to incur additional indebtedness and grant security interests with
respect thereto will be subject to the terms of the various indentures.
Liquidity. The ability of the Company to satisfy its obligations and fund
planned capital expenditures will be dependent upon its future performance,
which will be subject to prevailing economic conditions, including oil and gas
prices, and to financial and business conditions and other factors, many of
which are beyond its control, supplemented if necessary with existing cash
balances and borrowings under the OEI Credit Facility. The Company currently
expects that its cash flow from operations and availability under the OEI Credit
Facility will be adequate to execute its 1998 business plan. However, no
assurance can be given that the Company will not experience liquidity problems
from time to time in the future or on a long-term basis. If the Company's cash
flow from operations and availability under the OEI Credit Facility are not
sufficient to satisfy its cash requirements, there can be no assurance that
additional debt or equity financing will be available to meet its requirements.
Effects of Leverage. The Company has outstanding indebtedness of
approximately $673.2 million as of December 31, 1997. The Company's level of
indebtedness has several important effects on its future operations, including
(i) a substantial portion of the Company's cash flow from operations must be
dedicated to the payment of interest on its indebtedness and will not be
available for other purposes, (ii) the covenants contained in the various
indentures require the Company to meet certain financial tests, and contain
other restrictions which limit the Company's ability to borrow additional funds
or to dispose of assets and may affect the Company's flexibility in planning
for, and reacting to, changes in its business, including possible acquisition
activities and (iii) the Company's ability to obtain additional financing in the
future for working capital, expenditures, acquisitions, general corporate
purposes or other purposes may be impaired. None of the indentures place
significant restrictions on a wholly-owned subsidiaries' ability to make
distributions to the parent company.
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The Company believes it is currently in compliance with all covenants
contained in the respective Indentures and has been in compliance since the
issuance of the 13 1/2% Notes, the 9 3/4% Notes, the 8 7/8% Notes and the 10
3/8% Notes.
The Company's ability to meet its debt service obligations and to reduce
its total indebtedness will be dependent upon the Company's future performance,
which will be subject to oil and gas prices, general economic conditions and to
financial, business and other factors affecting the operations of the Company,
many of which are beyond its control. There can be no assurance that the
Company's future performance will not be adversely affected by such economic
conditions and financial, business and other factors.
OTHER MATTERS
Energy swap agreements. The Company engages in futures contracts with
certain of its production through master swap agreements ("Swap Agreements").
The Company considers these futures contracts to be hedging activities and, as
such, monthly settlements on these contracts are reflected in oil and gas sales.
In order to consider these futures contracts as hedges, (i) the Company must
designate the futures contract as a hedge of future production and (ii) the
contract must reduce the Company's exposure to the risk of changes in prices.
Changes in the market value of futures contracts treated as hedges are not
recognized in income until the hedged item is also recognized in income. If the
above criteria are not met, the Company will record the market value of the
contract at the end of each month and recognize a related gain or loss. Proceeds
received or paid relating to terminated contracts or contracts that have been
sold are amortized over the original contract period and reflected in oil and
gas sales. The Company enters into hedging activities in order to secure an
acceptable future price relating to a portion of future production. The primary
objective of these activities is to protect against decreases in price during
the term of the hedge.
The Swap Agreements provide for separate contracts tied to the NYMEX light
sweet crude oil and natural gas futures contracts. The Company has contracts
which contain specific contracted prices ("Swaps") that are settled monthly
based on the differences between the contract prices and the average NYMEX
prices for each month applied to the related contract volumes. To the extent the
average NYMEX price exceeds the contract price, the Company pays the spread, and
to the extent the contract price exceeds the average NYMEX price the Company
receives the spread. Under the terms of the Swap Agreements, each counterparty
has extended the Company a $5.0 million line of credit for use in conjunction
with its hedging activities. As of December 31, 1997, the fair market value of
all contracts covered by the Swap Agreements was approximately $6.8 million.
As of December 31, 1997, after giving effect to three hedges that were
unwound in January 1998, the Company's open forward position on its outstanding
crude oil Swaps was 4,500 MBbls at an average price of $19.88 per Bbl for the
year ended December 31, 1998. The Company had no outstanding natural gas Swaps
in 1998.
It is the Company's current intention to commit no more than 50% of its
production on a BOE basis to such arrangements at any point in time. As the
current swap agreements expire, the portion of the Company's oil and natural gas
production which is subject to price fluctuations will increase substantially,
unless the Company enters into additional hedging transactions.
Price fluctuations and volatile nature of markets. Despite the measures
taken by the Company to attempt to control price risk, the Company remains
subject to price fluctuations for natural gas and oil sold on the spot market.
Prices received for natural gas sold on the spot market are volatile due
primarily to seasonality of demand and other factors beyond the Company's
control. Domestic oil prices generally follow worldwide oil prices which are
subject to price fluctuations resulting from changes in world supply and demand.
Any significant decline in prices for oil and gas could have a material adverse
effect on the Company's financial position, results of operations and quantities
of reserves recoverable on an economic basis.
Environmental. The Company's business is subject to certain federal, state,
and local laws and regulations relating to the exploration for, and the
development, production and transportation of, oil and natural gas, as well as
environmental and safety matters. Many of these laws and regulations have become
more stringent in recent years, often imposing greater liability on a larger
number of potentially responsible parties. Although the Company believes it is
in substantial compliance with all applicable laws and regulations, the
requirements imposed by such laws and regulations are frequently changed and
subject to interpretation, and the Company is unable to predict the ultimate
cost of compliance with these requirements or their effect on its operations.
Under certain circumstances, the MMS may require any Company operations on
federal leases to be suspended or terminated. Any such suspensions, terminations
or inability to meet applicable bonding requirements could materially and
adversely affect the Company's financial condition and operations. Although
significant expenditures may be
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required to comply with governmental laws and regulations applicable to the
Company, to date such compliance has not had a material adverse effect on the
earnings or competitive position of the Company. It is possible that such
regulations in the future may add to the cost of operating offshore drilling
equipment or may significantly limit drilling activity. The Company has included
$10.0 million in its 1998 exploration and development capital budget to reformat
operations for alternative disposal of water produced from its offshore wells in
accordance with an approved zero discharge plan.
The OPA imposes ongoing requirements on a responsible party including proof
of financial responsibility to cover at least some costs in a potential spill.
For tank vessels, including mobile offshore drilling rigs, the OPA imposes on
owners, operators and charterers of the vessels, an obligation to maintain
evidence of financial responsibility of up to $10.0 million depending on gross
tonnage. With respect to offshore facilities, proof of greater levels of
financial responsibility may be applicable. This amount is subject to upward
regulatory adjustment up to $150.0 million.
Year 2000 compliance. The Company is currently in the process of evaluating
its information technology infrastructure for the year 2000 ("Year 2000")
compliance. The Company's primary information systems are in the process of
being replaced with fully compliant new systems as part of a regularly scheduled
upgrade to meet the Company's growing capacity and performance requirements.
These replacements are expected to be completed by early 1999.
The Company does not expect that the cost to modify and replace its
information technology infrastructure to be Year 2000 compliant will be material
to its financial condition or results of operations. The Company does not
anticipate any material disruption in its operations as a result of any failure
by the Company to be in compliance. The costs of these projects and the date on
which the Company plans to complete modifications and replacements are based on
management's best estimates, which were derived utilizing numerous assumptions
of future events including the continued availability of certain resources,
third party modification plans and other factors. However, there can be no
guarantee that these estimates will be achieved and actual results could differ
materially from those plans.
The Company does not currently have any information concerning the Year
2000 compliance status of its suppliers and customers. In the event that any of
the Company's significant suppliers or customers do not successfully and timely
achieve Year 2000 compliance, the Company's business or operations could be
adversely affected.
The Company has not incurred significant costs related to Year 2000
compliance prior to December 31, 1997, other than internal costs to evaluate the
extent of compliance.
Forward-looking statements. Certain statements in this report, including
statements of the Company's and management's expectation, intentions, plans and
beliefs, including those contained in or implied by "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Notes to
Supplemental Consolidated Financial Statements, are "forward-looking
statements", within the meaning of Section 21E of the Securities Exchange Act of
1934, that are subject to certain events, risk and uncertainties that may be
outside the Company's control. These forward-looking statements include
statements of management's plans and objectives for the Company's future
operations and statements of future economic performance; information regarding
drilling schedules, expected or planned production or transportation capacity,
future production levels of international and domestic fields, the Company's
capital budget and future capital requirements, the Company's meeting its future
capital needs, the Company's realization of its deferred tax assets, the level
of future expenditures for environmental costs and the outcome of regulatory and
litigation matters; and the assumptions described in this report underlying such
forward-looking statements. Actual results and developments could differ
materially from those expressed in or implied by such statements due to a number
of factors, including, without limitation, those described in the context of
such forward-looking statements, fluctuations in the price of crude oil and
natural gas, the success rate of exploration efforts, timeliness of development
activities, risk incident to the drilling and completion for oil and gas wells,
future production and development costs, the political and economic climate in
which the Company conducts operations and the risk factors described from time
to time in the Company's other documents and reports filed with the Securities
and Exchange Commission.
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