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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1999
COMMISSION FILE NUMBER 333-12707
MARINER ENERGY, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 86-0460233
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
580 WESTLAKE PARK BLVD., SUITE 1300
HOUSTON, TEXAS 77079
(Address of principal executive offices including Zip Code)
(281) 584-5500
(Registrant's telephone number)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirement for the past 90 days. Yes [ ] No [X]
Note: The Company is not subject to the filing requirements of the
Securities Exchange Act of 1934. This quarterly report is filed pursuant to
contractual obligations imposed on the Company by an Indenture, dated as of
August 1, 1996, under which the Company is the issuer of certain debt.
As of November 3, 1999, there were 1,378 shares of the registrant's
common stock outstanding.
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MARINER ENERGY, INC.
FORM 10-Q
2
SEPTEMBER 30, 1999
TABLE OF CONTENTS
Page
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PART I- FINANCIAL INFORMATION
Item 1. Balance Sheets at September 30, 1999 (unaudited) and December 31, 1998......................................1
Statements of Operations for the three and nine months ended
September 30, 1999 and 1998 (unaudited)...............................................................2
Statements of Cash Flows for the nine months ended September 30, 1999 and 1998 (unaudited)..................3
Notes to Financial Statements (unaudited)...................................................................4
Independent Certified Public Accountants' Report on Review of Interim Financial Information.................7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......................8
Item 3. Quantitative and Qualitative Disclosures about Market Risk.................................................16
PART II - OTHER INFORMATION
Item 1. Legal Proceedings..........................................................................................16
Item 2. Changes in Securities and Use of Proceeds..................................................................16
Item 3. Defaults Upon Senior Securities............................................................................16
Item 4. Submission of Matters to a Vote of Security Holders........................................................16
Item 5. Other Information..........................................................................................16
Item 6. Exhibits and Reports on Form 8-K...........................................................................17
SIGNATURE...........................................................................................................18
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PART I, ITEM 1.
MARINER ENERGY, INC.
BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
September 30, December 31,
1999 1998
------------- ------------
(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 1,326 $ 2
Receivables 15,373 16,387
Prepaid expenses and other 5,963 6,854
------------ ------------
Total current assets 22,662 23,243
------------ ------------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at full cost:
Proved 352,715 316,056
Unproved, not subject to amortization 90,573 84,076
------------ ------------
Total 443,288 400,132
Other property and equipment 3,846 3,300
Accumulated depreciation, depletion and amortization (190,569) (167,846)
------------ ------------
Total property and equipment, net 256,565 235,586
------------ ------------
OTHER ASSETS, NET OF AMORTIZATION 3,146 3,513
------------ ------------
TOTAL ASSETS $ 282,373 $ 262,342
============ ============
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES:
Accounts payable $ 19,627 $ 20,375
Accrued liabilities 20,733 29,082
Accrued interest 2,642 4,503
Revolving Credit Facility -- 53,400
Senior Credit Facility 25,000 --
------------ ------------
Total current liabilities 68,002 107,360
------------ ------------
OTHER LIABILITIES 3,806 2,824
LONG-TERM DEBT:
Senior Subordinated notes 99,661 99,624
Revolving Credit Facility 42,700 --
ENA Credit Facility -- 25,000
------------ ------------
Total long-term debt 142,361 124,624
------------ ------------
STOCKHOLDER'S EQUITY:
Common stock, $1 par value; 2,000 and 1,000 shares authorized, 1,378 and
1,000 issued and outstanding,
at September 30, 1999 and December 31, 1998, respectively 1 1
Additional paid-in-capital 172,318 124,856
Accumulated deficit (104,115) (97,323)
------------ ------------
Total stockholder's equity 68,204 27,534
------------ ------------
TOTAL LIABILITIES and STOCKHOLDER'S EQUITY $ 282,373 $ 262,342
============ ============
The accompanying notes are an integral part of these financial statements.
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MARINER ENERGY, INC.
STATEMENTS OF OPERATIONS
(UNAUDITED, IN THOUSANDS)
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------- --------------------------
1999 1998 1999 1998
---------- ---------- ---------- ----------
REVENUES:
Oil sales $ 2,462 $ 2,299 $ 7,086 $ 8,294
Gas sales 10,772 12,319 31,994 35,304
---------- ---------- ---------- ----------
Total revenues 13,234 14,618 39,080 43,598
---------- ---------- ---------- ----------
COSTS AND EXPENSES:
Lease operating expenses 2,616 2,702 8,380 7,554
Depreciation, depletion and amortization 7,564 8,749 23,367 25,023
General and administrative expenses 1,186 1,565 4,007 3,417
Provision for litigation -- -- -- 2,960
---------- ---------- ---------- ----------
Total costs and expenses 11,366 13,016 35,754 38,954
---------- ---------- ---------- ----------
OPERATING INCOME 1,868 1,602 3,326 4,644
INTEREST:
Income 8 16 29 299
Expense (3,536) (3,260) (10,147) (9,512)
---------- ---------- ---------- ----------
LOSS BEFORE TAXES (1,660) (1,642) (6,792) (4,569)
PROVISION FOR INCOME TAXES -- -- -- --
---------- ---------- ---------- ----------
NET LOSS $ (1,660) $ (1,642) $ (6,792) $ (4,569)
========== ========== ========== ==========
The accompanying notes are an integral part of these financial statements.
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MARINER ENERGY, INC.
STATEMENTS OF CASH FLOWS (UNAUDITED)
(IN THOUSANDS)
Nine Months Ended
September 30
--------------------------
1999 1998
---------- ----------
OPERATING ACTIVITIES:
Net loss $ (6,792) $ (4,569)
Adjustments to reconcile net loss to
net cash provided by operating activities:
Depreciation, depletion and amortization 23,740 25,287
Provision for litigation -- 2,960
Changes in operating assets and liabilities:
Receivables 193 2,666
Other current assets 891 (868)
Other assets 367 90
Accounts payable and accrued liabilities (10,957) (6,982)
---------- ----------
Net cash provided by operating activities 7,442 18,584
---------- ----------
INVESTING ACTIVITIES:
Additions to oil and gas properties (62,913) (102,661)
Additions to other property and equipment (546) (913)
Sale of mineral interest 19,757 --
---------- ----------
Net cash used in investing activities (43,702) (103,574)
---------- ----------
FINANCING ACTIVITIES:
Proceeds from (repayment of) Revolving Credit Facility (10,700) 37,000
Sale of common stock -- 10,000
Capital contributed by parent 23,284 28,992
Proceeds from the Senior Credit Facility 25,000 --
---------- ----------
Net cash provided by financing activities 37,584 75,992
---------- ----------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 1,324 (8,998)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 2 9,131
---------- ----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,326 $ 133
========== ==========
The accompanying notes are an integral part of these financial statements.
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MARINER ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
1. Basis of Presentation
The financial statements of Mariner Energy, Inc. (the "Company") included
herein have been prepared, without audit, pursuant to the rules and regulations
of the Securities and Exchange Commission ("SEC"). Accordingly, they reflect all
adjustments (consisting only of normal, recurring accruals) which are, in the
opinion of management, necessary for a fair presentation of the financial
results for the interim periods. Certain information and notes normally included
in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such rules and
regulations, although the Company believes that the disclosures are adequate to
make the information presented not misleading. These financial statements should
be read in conjunction with the financial statements and notes thereto included
in the Company's Form 10-K for the year ended December 31, 1998. The results of
operations and cash flows for the nine months ending September 30, 1998 and 1999
are not necessarily indicative of the results for the full year.
2. Oil and Gas Properties
Under the full cost method of accounting for oil and gas properties, the net
carrying value of proved oil and gas properties is limited to an estimate of the
future net revenues, discounted at 10%, from proved oil and gas reserves based
on period-end prices and costs plus the lower of cost or estimated fair value of
unproved properties.
In the second quarter of 1999, the Company sold a 63% working interest in
its Pluto Deepwater Gulf exploitation project. Net proceeds from this sale were
approximately $19.8 million.
3. Revolving Credit Facility
In June 1999, the borrowing base under the Company's revolving credit
facility (the "Revolving Credit Facility"), with Bank of America as agent for a
group of lenders, was reaffirmed at $60 million, and the maturity date of the
facility was extended from October 1, 1999 to October 1, 2002. As part of the
redetermination, the Company pledged certain mineral interests to secure the
Revolving Credit Facility. Accordingly, the Revolving Credit Facility was
reclassified from a current liability to a non-current liability as of the date
of the redetermination. In October 1999, the borrowing base under the Revolving
Credit Facility was again reaffirmed at $60 million as part of the semi-annual
borrowing base redetermination.
4. Affiliate Credit Facilities
During the first quarter of 1999, the Company's parent, Mariner Energy LLC
("LLC"), and Enron North America Corp. ("ENA"), formerly known as Enron Capital
& Trade Resources Corp., amended an existing unsecured, subordinated credit
facility (the "ENA Credit Facility") provided by ENA to LLC to increase the
amount available thereunder from $25 million to $50 million. In 1999, LLC has
contributed the net proceeds of $47.5 million from the ENA Credit Facility to
the Company in the form of common equity. The facility requires that any funds
received pursuant to a private or public equity or debt offering by LLC must
first be applied to repay the amount outstanding thereunder. Once funds
outstanding under the facility have been repaid, those funds may not be
reborrowed. The facility was also amended to extend its maturity date from April
30, 1999 to April 30, 2000, to accrue interest at an
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annual rate of LIBOR plus 4.5% with interest payable at maturity and to give ENA
the option to convert outstanding debt and accrued interest under the facility
to equity in LLC at any time through maturity.
The Board of Directors of LLC has resolved not to require the use of cash
flow from the Company's operations or sales of the Company's stock or assets to
repay the amounts outstanding under the ENA Credit Facility. In addition,
restrictions under the Revolving Credit Facility and the 10-1/2% Senior
Subordinated Notes restricts the use of the Company's assets or cash flow to
satisfy interest or principal payments on the ENA Credit Facility. Consequently,
the Company has reclassified the ENA Credit Facility balance as of January 1,
1999, net of capitalized fees, to equity. This reclassification was not included
in the cash flow statement as it represented a non-cash transaction.
In May 1999, the Company established a $25 million borrowing-based,
short-term credit facility with ENA (the "Senior Credit Facility"). This
facility matures on December 31, 1999 and has an annual interest rate of LIBOR
plus 2.5%, with interest payments due quarterly. As of September 30, 1999, the
Company had fully drawn this facility.
5. Commitments and Contingencies
Hedging - The Company uses crude oil and natural gas price swaps and
other similar hedging transactions to reduce its exposure to price decreases. In
January 1999, the Company entered into a 36 month long-term natural gas fixed
price swap ("Fixed Price Swap") for the period November 1, 1999 through October
31, 2002 for a portion of its natural gas production at $2.18 per Mmbtu. In May
1999, the Company entered into a five month market sensitive swap ("Market
Sensitive Swap") for the period November 1, 1999 through March 31, 2000 where
the Company pays to the counterparty $2.60 per Mmbtu in return for a market
sensitive price. The effect of the Market Sensitive Swap is to limit hedging
losses on a portion of the Fixed Price Swap described above. In the nine-month
period ended September 30, 1999, the Company recognized approximately $4.5
million in losses before recovery in the cash market as a result of these
contracts.
The following table sets forth the Company's open hedging positions as of
September 30, 1999.
PRICES
----------------------------------------
COLLAR
NOTIONAL ------------------------- FAIR VALUE AT
TIME PERIOD QUANTITIES FLOOR CEILING FIXED SEPTEMBER 30, 1999
- ------------- ---------- ---------- ---------- ---------- ------------------
(IN THOUSANDS)
NATURAL GAS (MMBTU)
October 1 - October 31, 1999...... 1,860 $ 1.85 $ 2.05 -- $ (1,042)
November 1 - December 31, 1999
Fixed Price Swap............... 2,684 -- -- $ 2.18 $ (1,759)
Market Sensitive Swap.......... 1,220 -- -- $ 2.60 $ 303
January 1 - December 31, 2000
Fixed Price Swap............... 10,980 -- -- $ 2.18 $ (5,215)
Market Sensitive Swap.......... 1,820 -- -- $ 2.60 $ 404
January 1 - December 31, 2001
Fixed Price Swap............... 4,380 -- -- $ 2.18 $ (1,920)
January 1 - October 31, 2002
Fixed Price Swap............... 1,824 -- -- $ 2.18 $ (774)
CRUDE OIL (BBL)
October 1 - December 31, 1999..... 110,400 -- -- $ 16.54 $ (868)
November 1 - December 31, 1999.... 94,583 -- -- $ 19.89 $ (418)
January 1 - December 31, 2000..... 1,481,991 -- -- $ 18.72 $ (3,364)
Per the counterparty's option, subsequent to September 30, 1999, the
Company's collar on natural gas covering the period July 1, 1999 through October
31, 1999 was extended at a floor price of $2.00 per MMBtu and a ceiling of $2.70
per MMBtu for the period November 1999 through March 2000. All
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hedging contracts mentioned above were entered into with an affiliate of the
Company. Including these contracts, hedging arrangements for 1999 cover
approximately 70% of the Company's expected 1999 equivalent production. The
Company also purchased two gas call options for November 1999 and December 1999
for a cumulative notional quantity of 1,098 MMBtu at an exclusive price of $4.25
per MMBtu and $4.50 per MMBtu, respectively.
The fair value of our hedging instruments was determined based on a
brokers' forward price quote and a NYMEX forward price quote. As of September
30, 1999 a commodity price increase of 10% would have resulted in an unfavorable
change in fair value of $8.5 million and a commodity price decrease of 10% would
have resulted in a favorable change in fair value of $8.5 million.
Deepwater Rig - The Company executed a letter of intent in February 1998
regarding the provision of a deepwater rig to the Company and another company on
an equally shared basis for five years beginning in early 2000. The letter of
intent also provided for a day rate of $158,500. It is the third party's
position that the Company is committed to the terms of the letter of intent. The
Company is currently in discussions with the owner of the rig to determine if a
mutually acceptable drilling contract can be negotiated.
Flow Line Sale - The Company has entered into an agreement with an
affiliate to sell the Pluto flow line and related facilities and enter into a
firm transportation agreement for the same flow line. Closing of this
transaction will occur after the Pluto project commences production.
6. New Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities" which was amended in June 1999 by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement No. 133 - an amendment of FASB
Statement No. 133." SFAS No. 133, as amended, is effective for fiscal years
beginning after June 15, 2000 and establishes accounting and reporting standards
for derivative instruments and for hedging activities. The Company is currently
evaluating what effect, if any, SFAS No. 133 will have on the Company's
financial statements. The Company will adopt this statement no later than
January 1, 2001.
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INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS' REPORT ON REVIEW OF INTERIM FINANCIAL
INFORMATION
Board of Directors and Stockholder
Mariner Energy, Inc.
Houston, Texas
We have reviewed the accompanying balance sheet of Mariner Energy, Inc. as of
September 30, 1999 and the related statements of operations for the three-month
and nine-month periods ended September 30, 1999 and 1998 and of cash flows for
the nine-month periods ending September 30, 1999 and 1998. These financial
statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists primarily of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the accompanying consolidated financial statements for them to be in
conformity with generally accepted accounting principles.
We have previously audited, in accordance with generally accepted auditing
standards, the balance sheet as of December 31, 1998, and the related statements
of operations, stockholder's equity, and cash flows for the year ended December
31, 1998 (not presented herein), and in our report dated April 14, 1999, we
expressed an unqualified opinion on those financial statements. In our opinion,
the information set forth in the accompanying balance sheet as of December 31,
1998 is fairly stated, in all material respects, in relation to the balance
sheet from which it has been derived.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Houston, Texas
November 4, 1999
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PART I, ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
The following review of operations for the three-month and nine-month
periods ended September 30, 1999 and 1998 should be read in conjunction with the
financial statements of the Company and Notes thereto included elsewhere in this
Form 10-Q and with the Financial Statements, Notes, and Management's Discussion
and Analysis of Financial Condition and Results of Operations included in the
Company's Annual Report on Form 10-K for the year ended December 31, 1998, filed
with the Securities and Exchange Commission on April 15, 1999.
INFORMATION REGARDING FORWARD LOOKING STATEMENTS
All statements other than statements of historical fact included in
this quarterly report on Form 10-Q, including, without limitation, statements
contained in this "Management's Discussion and Analysis of Financial Condition
and Results of Operations" regarding the Company's financial position, business
strategy, plans and objectives of management of the Company for future
operations, Year 2000 readiness, and industry conditions, are forward-looking
statements. Although the Company believes that the expectations reflected in
such forward-looking statements are reasonable, it can give no assurance that
such expectations will prove to have been correct, and actual results could
differ materially from the Company's expectations. Factors that could influence
these results include, but are not limited to, oil and gas price volatility,
results of future drilling, availability of drilling rigs, future production and
costs, and other factors described in the Company's annual report on Form 10-K
for the year ended December 31, 1998, filed with the Securities and Exchange
Commission on April 15, 1999.
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RESULTS OF OPERATIONS
The following table sets forth certain information regarding results of
operations for the periods shown:
Three Months Ended Nine Months Ended
September 30 September 30
------------------------- ------------------------
1999 1998 1999 1998
---------- ----------- ---------- ----------
Total revenue, $MM $ 13.2 $ 14.6 $ 39.1 $ 43.6
EBITDA(a), $MM 9.4 10.3 26.7 32.6
Net income (loss), $MM (1.7) (1.6) (6.8) (4.6)
Production:
Oil and condensate (Mbbls) 154 183 502 625
Natural Gas (Mmcf) 4,976 5,108 15,559 14,591
Natural Gas equivalents (Mmcfe) 5,900 6,206 18,571 18,341
Average realized sales prices:
Oil and condensate ($/Bbl) $ 16.01 $ 12.56 $ 14.12 $ 13.27
Natural Gas ($/Mcf) 2.16 2.41 2.06 2.42
Natural Gas equivalents ($/Mcfe) 2.24 2.36 2.10 2.38
Cash Margin(b), per Mcfe:
Revenue (pre-hedge) $ 2.84 $ 2.15 $ 2.35 $ 2.28
Hedging impact (0.60) 0.21 (0.25) 0.10
Lease operating expenses (0.44) (0.44) (0.45) (0.41)
Gross G&A costs (0.44) (0.56) (0.47) (0.45)
---------- ---------- ---------- ----------
Cash Margin $ 1.36 $ 1.36 $ 1.18 $ 1.52
========== ========== ========== ==========
Capital Expenditures, $MM:
Exploration:
Leasehold and G&G costs(c) $ 1.3 $ 3.5 $ 1.2 $ 43.8
Drilling 3.1 2.1 3.8 19.3
Development & other(c) 17.9 11.6 31.9 33.8
Capitalized G&A and interest costs 2.1 2.7 6.8 6.7
---------- ---------- ---------- ----------
Total $ 24.4 $ 19.9 $ 43.7 $ 103.6
========== ========== ========== ==========
(a) - EBITDA equals earnings before interest, income taxes, depreciation,
depletion, amortization, provision for litigation and impairment of oil
and gas properties. EBITDA should be used as a supplement to, and not as
a supplement for, net earnings and cash provided by operating activities
(as disclosed in the financial statements) in analyzing the Company's
results of operations and liquidity.
(b) - Cash margin measures the net cash generated by a company's operations
during a given period, without regard to the period such cash is
physically received or spent by the company.
(c) - In the second quarter of 1999, Leasehold and G&G costs and Development &
other costs were reduced by $12.2 million and $7.6 million, respectively,
as a result of the sale of a 63% working interest in the Company's Pluto
Deepwater Gulf exploitation project.
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RESULTS OF OPERATIONS FOR THE THIRD QUARTER OF 1999
NET PRODUCTION decreased 5% to 5.9 Bcfe for the third quarter of 1999 from
6.2 Bcfe for the third quarter of 1998. Production from the Company's offshore
Gulf of Mexico properties increased to 4.3 Bcfe in the quarter from 3.2 Bcfe in
the same period of 1998, as a result of the production from the Dulcimer
project at Garden Banks 367, which began in April 1999, and increased
production at Galveston 151, offset in part by natural production declines on
other producing properties. This increase was more than offset by reduced
production from the Company's Sandy Lake field onshore Texas due to production
decline throughout the field. Total Company production for the remainder of
1999 is anticipated to increase, as a result of the expected commencement of
production from the Pluto field in the fourth quarter.
HEDGING ACTIVITIES for the third quarter of 1999 decreased the Company's
average realized natural gas sales price received by $0.60 per Mcf and revenues
by $3.0 million, compared with an increase of $0.26 per Mcf and $1.3 million
for the same period of 1998. Hedging related to crude oil during the third
quarter of 1999 decreased the Company's average realized crude oil sales price
received by $3.70 per Bbl and revenues by $0.6 million. There were no hedging
activities for crude oil in the same period of 1998.
OIL AND GAS REVENUES decreased 9% to $13.2 million for the third quarter of
1999 from $14.6 million for the third quarter of 1998, primarily due to a 5%
decrease in production and to a 5% decrease in realized prices, to $2.24 per
Mcfe for the third quarter from $2.36 per Mcfe in the same period of 1998.
LEASE OPERATING EXPENSES decreased 3% to $2.6 million for the third quarter
of 1999, from $2.7 million for the third quarter of 1998, due to lower ad
valorem and severance taxes on the Company's onshore properties.
DEPRECIATION, DEPLETION, AND AMORTIZATION EXPENSE (DD&A) decreased 14% to
$7.6 million for the third quarter of 1999 from $8.7 million for the third
quarter of 1998, as a result of the 5% decrease in equivalent volumes produced
and a decrease in the unit-of-production depreciation, depletion, and
amortization rate to $1.28 per Mcfe from $1.41 per Mcfe. The lower rate for the
third quarter of 1999 was due to the $50.8 million non-cash full cost ceiling
test impairment recorded in 1998.
GENERAL AND ADMINISTRATIVE EXPENSES, which are net of overhead
reimbursements received by the Company from other working interest owners,
decreased 24% to $1.2 million for the third quarter of 1999 from $1.6 million
for the third quarter of 1998, due to increased overhead recovery in relation
to our Pluto project in progress during the third quarter 1999.
INTEREST EXPENSE for the third quarter of 1999 increased 8% to $3.5 million
from $3.3 million in the third quarter of 1998, due to additional borrowings by
the Company under the $25 million Senior Credit Facility obtained in May 1999.
LOSS BEFORE INCOME TAXES was $1.6 million for the third quarter of 1999, as
a result of the gas revenue decrease and increased expenses as discussed above.
RESULTS OF OPERATIONS FOR THE FIRST NINE MONTHS OF 1999
NET PRODUCTION increased 1% to 18.6 Bcfe for the first nine months of 1999
from 18.3 Bcfe for the same period of 1998. Production from the Company's
offshore Gulf of Mexico properties increased to 13.0 Bcfe in the nine-month
period ended September 30, 1999 from 9.6 Bcfe in the same period of 1998,
primarily as a result of production commencing from the Dulcimer field located
in Garden Banks block 367 and two new wells in the Rembrandt field located in
Galveston block 151. This increase was offset by reduced production from the
Company's Sandy Lake field onshore Texas due to continuing natural production
decline in the field. Total Company production for the remainder of 1999 is
anticipated to increase primarily as a result of the expected commencement of
production from the Pluto field in the fourth quarter.
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HEDGING ACTIVITIES for the first nine months of 1999 decreased our average
realized natural gas price received by $0.24 per Mcf and revenues by $3.8
million, compared with an increase of $0.12 per Mcf and revenues of $1.8
million. Our hedging activities with respect to crude oil for the first nine
months of 1999 reduced the average sales price received by $1.32 per Bbl and
revenues by $0.7 million. There were no oil hedges in 1998.
OIL AND GAS REVENUES decreased 10% to $39.1 million for the first nine
months of 1999 from $43.6 million for the comparable period of 1998, due to a
12% decrease in realized prices to $2.10 per Mcfe in the first nine months of
1999 from $2.38 per Mcfe in the same period last year, which decrease was
offset in part by the production increase discussed above.
LEASE OPERATING EXPENSES increased 11% to $8.4 million for the first nine
months of 1999, from $7.6 million for the comparable period of 1998, due to the
higher offshore production discussed above and well workovers on two offshore
wells and two wells in the Company's Sandy Lake field.
DEPRECIATION, DEPLETION, AND AMORTIZATION EXPENSE (DD&A) decreased 7% to
$23.4 million for the first nine months of 1999 from $25.0 million for the
comparable period of 1998, as a result of the decrease in the
unit-of-production depreciation, depletion, and amortization rate to $1.26 per
Mcfe from $1.36 per Mcfe, offset in part by a 1% increase in equivalent volumes
produced. The lower rate for the first nine months of 1999 was due to the $50.8
million non-cash full cost ceiling test impairment recorded in 1998.
GENERAL AND ADMINISTRATIVE EXPENSES, which are net of overhead
reimbursements received by the Company from other working interest owners,
increased 17% to $4.0 million for the first nine months of 1999 from $3.4
million for the comparable period of 1998, due to increased personnel-related
costs in 1999 required for the Company to pursue its Deepwater Gulf exploration
and development plan.
INTEREST EXPENSE for the first nine months of 1999 increased 7% to $10.1
million from $9.5 million for the comparable period of 1998, due to additional
borrowings by the Company under a $25 million Senior Credit Facility entered
into during the second quarter of 1999.
LOSS BEFORE INCOME TAXES was $6.8 million for the first nine months of 1999,
primarily as a result of the oil and gas revenue decreases and increased
expenses discussed above.
LIQUIDITY, CAPITAL EXPENDITURES AND CAPITAL RESOURCES
As of September 30, 1999, the Company had a working capital deficit of
approximately $45.3 million, compared to a working capital deficit of $84.1
million at December 31, 1998. The reduction in the working capital deficit was
a result of the reclassification of the Company's Revolving Credit Facility
back to long-term debt. At December 31, 1998, the Revolving Credit Facility was
scheduled to mature on October 1, 1999, requiring the Company to classify
outstanding borrowings under the facility as current liabilities. Subsequent to
December 31, 1998, the Company reached an agreement with the Company's bank
group to extend the facility's maturity to October 1, 2002. As a result, the
Company classified the balance under the facility as long-term debt, payment of
accounts payable and accrued liabilities partially offset by $25 million drawn
under the Senior Credit Facility. The Company expects its 1999 capital
expenditures, including capitalized indirect costs and reduced by proceeds from
the sale of 63% of the Company's Pluto project, to be approximately $55
million, which would exceed cash flow from operations. We expect our 2000
capital expenditures to be approximately $110 million, which would exceed
expected cash flow from operations for 2000. There can be no assurance that the
Company's access to capital will be sufficient to meet its needs for capital.
As such, the Company may be required to reduce its planned capital expenditures
and forego planned exploratory drilling or monetize portions of its proved
reserves or undeveloped inventory if additional capital resources are not
available to the Company on terms it considers reasonable.
Net cash provided by operating activities was $7.4 million in the first nine
months of 1999, a decrease of $11.1 million from the same period of 1998. A
period to period decrease of approximately $6.4 million in
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operating cash flow before changes in working capital was due primarily to
lower commodity prices, increased expenses, and a $3.0 million provision for
litigation in 1998. The remaining decrease of $4.7 million in net cash was used
for changes in working capital, payments of accounts payable partially offset
by collection of receivables.
Cash used in investing activities in the first nine months of 1999 decreased
to $43.7 million from $103.6 million for the same period in 1998 due primarily
to fewer exploratory leasehold acquisitions and lower exploratory drilling
expenditures and reimbursements received from a partner on the Company's Pluto
project.
Cash provided by financing activities was $37.6 million for the first nine
months of 1999 compared to $76.0 million for the same period in 1998. The
Company's primary source of cash for the first nine months of 1999 was $23.3
million in proceeds from a capital contribution from LLC, which funds were
provided to LLC through a credit facility with ENA, and $25.0 million from a
short-term credit facility with ENA, offset in part by a net $10.7 million
repayment of borrowings under the Company's Revolving Credit Facility.
The energy markets have historically been very volatile, and there can be no
assurance that oil and natural gas prices will not be subject to wide
fluctuations in the future. To reduce the effects of the volatility of the
price of oil and natural gas on the Company's operating cash flow, management
has adopted a policy of hedging oil and natural gas prices from time to time
through the use of commodity futures, options and swap agreements. While the
use of these hedging arrangements limits the downside risk of adverse price
movements, it may also limit future gains from favorable movements.
The following table sets forth the increase (decrease) in the Company's oil
and natural gas sales as a result of hedging transactions and the effects of
hedging transactions on prices during the periods indicated.
Nine Months Ended September 30,
-----------------------------------------
1999 1998
------------------- ------------------
Increase (decrease) in natural gas sales (in thousands)............. ($3,818) $1,777
Decrease in oil sales (in thousands)................................ (666) -
Effect of hedging transactions on average natural gas sales price
(per Mcf)........................................................... (0.24) 0.12
Effect of hedging transactions on average oil sales price
(per Bvbl).......................................................... (1.32) -
A table setting forth the Company's open hedging positions as of September
30, 1999 is contained in footnote 5. "Commitments and Contingencies" in the
footnotes to the financial statements in Part I, Item 1. of this report.
Hedging arrangements for 1999 cover approximately 70% of the Company's
anticipated equivalent production for the year. Hedging arrangements for 2000,
2001 and 2002 cover approximately 40%, 10% and 3% of the Company's anticipated
equivalent production for those years, respectively.
Capital expenditures for the first nine months of 1999 were $56.7 million
excluding the 19.8 million related to the Company's sale of a 63% working
interest in the Pluto project and $6.8 million of capitalized indirect costs.
Capital expenditures included $17.2 million for exploration activities and
$39.5 million for development. Included in exploration expenditures was $8.9
million for lease bonus payments on three deepwater Gulf of Mexico blocks
awarded to the Company in the March, 1999 Central Gulf of Mexico Lease Sale.
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During the nine-month period ended September 30, 1999, the Company announced
a discovery in the Deepwater Gulf of Mexico on its Aconcagua prospect located
in Mississippi Canyon block 305 in 7,100 feet of water. As a result of previous
arrangements, Mariner's share of the exploratory drilling costs for this well
was covered by its partners. An appraisal well is planned for late 1999 or
early 2000 to quantify reserve estimates and to ensure appropriate development.
A successful exploratory well was also announced at the Company's Apia
prospect located in Garden Banks block 73 in 700 feet of water. Production from
the well is expected to commence in the second quarter of 2000.
The Company was the high bidder on three blocks in the Deepwater Gulf of
Mexico at the Central Gulf of Mexico oil and gas lease sale held in March 1999.
Mariner's share of the bids was $8.9 million, all of which was paid by
September 30, 1999.
During the remainder of 1999, the Company expects to complete drilling
operations on three or four exploratory wells, including two in the Deepwater
Gulf. The majority of the Company's share of exploratory costs on one of the
anticipated Deepwater Gulf wells would be covered by the Company's partners in
the well. The Company also expects to drill an onshore development well, an
appraisal well on the Aconcagua discovery, and to complete the drilling of the
production well and related facilities necessary for the Pluto project to
commence production in the fourth quarter of 1999. The Company has entered into
an agreement with an affiliate to sell the Pluto flow line and related
facilities and enter into a firm transportation agreement for the same flow
line. Total capital expenditures for 1999 including capitalized indirect costs
and reduced by proceeds from the sale of 63% of the Company's Pluto Deepwater
Gulf exploitation project are expected to be approximately $55 million.
Debt outstanding as of September 30, 1999 was approximately $167.4 million,
including $99.7 million of senior subordinated notes, $42.7 million drawn on
the Revolving Credit Facility, both of which were classified as long-term debt,
and $25 million drawn on the Senior Credit Facility with ENA. Following the
semi-annual borrowing base redetermination, in May 1999, the borrowing base
under the Revolving Credit Facility was reaffirmed at $60 million and the
maturity date of the facility was extended from October 1, 1999 to October 1,
2002. As part of the redetermination, the Company pledged certain mineral
interests to secure the Revolving Credit Facility. The borrowing base was also
reaffirmed at $60 million following completion of the mid-year 1999
redetermination in October 1999.
In April 1999, the Company established a $25 million borrowing-based, Senior
Credit Facility with ENA to obtain funds needed to execute the Company's 1999
capital expenditure program and for short-term working capital needs. The
Senior Credit Facility matures on December 31, 1999, and is expected to be
repaid from internally generated cash flows.
There can be no assurance that funds available to the Company under the
Revolving Credit Facility and the ENA Senior Credit Facility will be sufficient
for the Company to fund its currently planned capital expenditures. Further,
there can be no assurance that the Company's cash flows will be sufficient to
repay the ENA Senior Credit Facility when it matures in December 1999. The
Company may be required to reduce its planned capital expenditures and forego
planned exploratory drilling or to monetize portions of its proved reserves or
undeveloped inventory if additional capital resources are not available to the
Company on terms it considers reasonable.
During the first quarter of 1999, LLC and ENA amended the ENA Credit
Facility to increase the amount available thereunder from $25 million to $50
million. At June 30, 1999, LLC had fully drawn this facility and contributed
the net proceeds to the Company as equity. The facility requires that a portion
of the proceeds of any private or public equity or debt offering by LLC be
applied to repay amounts outstanding under that facility, following which no
additional amounts will be available for borrowing under the facility. The
facility has also been amended to extend its maturity from April 30, 1999 to
April 30, 2000, and to give ENA the option to convert the facility to equity in
the Company's parent at any time through maturity. Restrictions on the
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Company's subordinated notes and Revolving Credit Facility effectively contains
restrictions on the Company from using its assets or cash flow to satisfy
interest or principal payments for the ENA Credit Facility.
The Company believes it will have adequate cash flow in order for the Company
to fund its remaining planned activities in 1999. A portion of the Company's
capital needs during the remainder of 1999 are expected to be funded by the sale
of the flow line and related facilities on the Pluto project to an affiliate of
ENA. However, the Company probably will be required to raise additional debt
and/or equity financing to fund part of its planned activities in the year 2000.
The Company's capital resources still may not be sufficient to meet the
Company's anticipated future requirements for working capital, capital
expenditures and scheduled payments of principal and interest on its
indebtedness. There can be no assurance that anticipated growth will be
realized, that the Company's business will generate sufficient cash flow from
operations or that future borrowings or equity capital will be available in an
amount sufficient to enable the Company to service its indebtedness or make
necessary capital expenditures. In addition, depending on the levels of its cash
flow and capital expenditures (the latter of which are, to a large extent,
discretionary), the Company may need to refinance a portion of the principal
amount of its senior subordinated debt at or prior to maturity. However, there
can be no assurance that the Company would be able to obtain financing on
acceptable terms to complete a refinancing.
YEAR 2000 COMPLIANCE
The year 2000 issue concerns the ability of information technology and
non-information technology systems and processes to recognize and process
properly date-sensitive information before, during and after December 31, 1999.
State of readiness
The Company has been following a year 2000 project life cycle methodology
that includes the following phases:
o an initial assessment and inventory of year 2000 issues;
o the development of a detailed plan to address year 2000 issues;
o the testing of our systems with year 2000 issues;
o the remediation and upgrade of year 2000 issues;
o contingency planning related to worst-case scenarios; and
o an assessment of business partners' readiness.
The Company has completed the first three phases and is materially
complete with the remediation and upgrade phase as of October 31, 1999. We are
now focused on finalizing the contingency planning and business partner
readiness phases.
The Company conducted the initial assessment and inventory phase in
February 1999. This phase consisted of an assessment of all computer automation
in the following areas:
o business application systems;
o information technology infrastructure and computing environment;
o geophysical and exploration hardware and software;
o field automation and process control;
o communications; and
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o corporate office infrastructure.
The initial assessment and inventory results showed that, according to
third-party providers, manufacturers and vendors, over 90% of these items were
year 2000-ready. The Company is currently executing a detailed plan to
remediate the remaining 10%. As of October 31, 1999, the Company is
approximately 97% complete with respect to all known items that require
replacement or mediation. The remaining items are in progress with an expected
completion date of November 22, 1999. The one remaining remediation item
consists of integrating one non-compliant operations control system to an
existing year 2000-ready system at the Garden Banks 367.
Because the year 2000 issue is a unique event with no historical
perspective, the Company cannot guarantee we will have no year 2000 problems or
that these problems will not be material. However, the Company is taking
reasonable measures to prevent year 2000 business failures. The Company is
following a structured plan, the Company has established an executive committee
to oversee the plan and we have recently completed various technology updates.
Business partner readiness
The year 2000 issue affects all of the Company's customers, vendors and
other key business partners. Therefore, the Company has implemented a business
partner readiness program in which the Company will assess all key business
partners' year 2000 readiness by:
o directly contacting the business partner;
o accessing the business partner's web site; or
o reviewing the business partner's Securities and Exchange Commission
filings.
The Company expects to complete this program by November 15, 1999.
Costs to address year 2000 issues
Costs directly related to the year 2000 issue have been approximately
$110,000, including external consulting fees. Approximately $50,000 of this
amount has been capitalized and attributed to the replacement of desktop and
server hardware acquisitions. The Company expensed the remaining $60,000. The
Company does not expect to incur any additional costs directly related to the
year 2000 issue. However, the Company cannot assure that the Company will not
incur additional costs.
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Year 2000 risk factors
The most significant year 2000 risk factor relates to the readiness of
third-party hardware and software manufacturers and key business partners. The
Company is relying on their responses that they will be ready. However, we
cannot assure you that these third parties will be ready or predict with
certainty the effect of their unreadiness.
The most likely "worst case" scenarios are:
o prolonged loss of power or mechanical failure that could jeopardize the
Company's production and transportation operations;
o third-party suppliers' failure to deliver production supplies, which
failure would adversely affect the Company's drilling and production
process; and
o an inability to process financial transactions with banks or to bill,
receive or process payments from customers.
Contingency plans
Initial draft written contingency plans have been developed to address each
of the worst case scenarios. These drafts are expected to be finalized by
November 22, 1999.
Statements in this section are "Year 2000 Readiness Disclosure" within the
meaning of the Year 2000 Information and Readiness Disclosure Act, however this
Act does not protect against matters arising under Federal Securities Laws.
PART I, ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
See Part I, Item 2. "Management's Discussion and Analysis of Financial
Condition and Results of Operations".
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) The following exhibits are filed herewith.
27.1 Financial Data Schedule
(b) The Company filed no Current Reports on Form 8-K during the quarter
ended September 30, 1999.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
MARINER ENERGY, INC.
Date: November 4, 1999 /s/ Frank A. Pici
-------------------------------------
Frank A. Pici
Vice President of Finance and
Chief Financial Officer
(Principal Financial Officer and
Officer Duly Authorized to Sign
on Behalf of the Registrant)
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INDEX TO EXHIBITS
27.1 -- Financial Data Schedule