Third Quarter 2001 Form 10-Q Mariner Energy, Inc.

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, 2001



Commission file number 333-12707

Mariner Energy, Inc.
(Exact name of registrant as specified in its charter)

Internal Revenue Service - Employer Identification No. 86-0460233
State of other jurisdiction of incorporation or organization - Delaware


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 2, 2001, there were 1,380 shares of the registrant's common stock outstanding.




MARINER ENERGY, INC.
Form 10-Q
September 30, 2001

TABLE OF CONTENTS
Page
PART I - FINANCIAL INFORMATION
Item 1.Condensed Balance Sheets at September 30, 2001 (unaudited) and December 31, 20001
Condensed Statements of Operations for the three-months
and nine-months ended September 30, 2001 and 2000 (unaudited)
2
Condensed Statements of Cash Flows for the nine-months
ended September 30, 2001 and 2000 (unaudited)
3
Notes to Condensed Financial Statements (unaudited)4
Independent Accountants' Report9
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations10
Item 3.Quantitative and Qualitative Disclosures about Market Risk15

PART II - OTHER INFORMATION
Item 1.Legal Proceedings15
Item 2.Changes in Securities and Use of Proceeds15
Item 3.Defaults Upon Senior Securities15
Item 4.Submission of Matters to a Vote of Security Holders15
Item 5.Other Information15
Item 6.Exhibits and Reports on Form 8-K15

SIGNATURE
16

Part I, Item 1.

MARINER ENERGY, INC.
CONDENSED BALANCE SHEETS
(in thousands)
September 30,December 31,

2001          

2000         


(Unaudited)

ASSETS

CURRENT ASSETS:
    Cash and cash equivalents$1,859$2,389
    Receivables46,49933,534
    Hedge receivable21,891--
    Prepaid expenses and other12,1605,991


       Total current assets82,40941,914


PROPERTY AND EQUIPMENT:
    Oil and gas properties, at full cost:
       Proved572,401478,596
       Unproved, not subject to amortization55,81761,068


          Total628,218539,664
       Other property and equipment5,4454,592
    Accumulated depreciation, depletion and amortization(303,365)(254,396)


          Total property and equipment, net330,928289,860
OTHER ASSETS, Net of amortization3,4433,653


HEDGE RECEIVABLE6,318--


TOTAL ASSETS422,468335,427


LIABILITIES AND STOCKHOLDER'S EQUITY

CURRENT LIABILITIES:
    Accounts payable$77,633$37,600
    Accrued liabilities27,44115,144
    Accrued interest1,8064,522


       Total current liabilities106,88057,266
OTHER LIABILITIES8,0096,552
LONG-TERM DEBT:
    Revolving credit facility--30,000
    Senior Subordinated Notes99,75999,722


       Total long-term debt99,759129,722


STOCKHOLDER'S EQUITY:
    Common stock, $1 par value; 2,000 shares authorized,
    1,380 issued and outstanding
11
    Additional paid-in-capital227,318227,318
    Other comprehensive income28,209--
    Accumulated deficit(47,708)(85,432)


       Total stockholder's equity207,820141,887


TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY$422,468$335,427


The accompanying notes are an integral part of these financial statements.



MARINER ENERGY, INC.
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited, in thousands)

Three-Months Ended
September 30
Nine-Months Ended
September 30


2001   2000   2001   2000   




REVENUES:
    Oil sales$18,046$ 5,964$56,008$23,925
    Gas sales17,05521,66370,76065,142




        Total revenues35,10127,627126,76889,067




COSTS AND EXPENSES:
    Lease operating expenses4,9624,41215,37212,882
    Transportation2,4882,2469,8745,378
    Depreciation, depletion and amortization15,55212,75349,74841,741
    General and administrative expenses4,3371,3578,0424,611




        Total costs and expenses27,33920,76883,03664,612




OPERATING INCOME7,7626,85943,73224,455
INTEREST:
    Income2384556398
    Expense(2,220)(2,648)(6,571)(8,807)




INCOME BEFORE TAXES5,7804,25637,72415,746
PROVISION FOR INCOME TAXES----




NET INCOME$5,780$4,256$37,724$15,746





The accompanying notes are an integral part of these financial statements.



MARINER ENERGY, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)
Nine-Months Ended
September 30,

20012000


OPERATING ACTIVITIES:
    Net Income$37,724$15,746
    Adjustments to reconcile net income to
       net cash provided by (used in) operating activities:
           Depreciation, depletion and amortization50,46342,277
    Changes in operating assets and liabilities:
           Receivables(12,965)(12,244)
           Other current assets(6,169)(432)
           Other assets210(29)
           Accounts payable and accrued liabilities49,614(8,687)


       Net cash provided by operating activities118,87736,631


INVESTING ACTIVITIES:
    Additions to oil and gas properties(128,054)(83,299)
    Proceeds from property conveyances39,50029,002
    Additions to other property and equipment(853)(304)


       Net cash used in investing activities(89,407)(54,601)


FINANCING ACTIVITIES:
    Payments to revolving credit facility(30,000)(7,600)
    Capital contribution from parent--55,000
    Payments to senior credit facility--(25,000)


       Net cash provided (used by) by financing activities(30,000)22,400


INCREASE (DECREASE) IN CASH AND CASH EQUIV.(530)4,430
CASH AND CASH EQUIV. AT BEGINNING OF PERIOD2,389123


CASH AND CASH EQUIV. AT END OF PERIOD$1,859$4,553



The accompanying notes are an integral part of these financial statements.



MARINER ENERGY, INC.

Notes to Condensed Financial Statements

(unaudited)

1.      BASIS OF PRESENTATION

      The condensed 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 condensed financial statements prepared in accordance with accounting principles generally accepted in the United States of America 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 condensed 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, 2000. The results of operations for the three and nine-months ended September 30, 2001 and the cash flows for the nine-months ended September 30, 2001 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, plus the lower of cost or estimated fair value of unproved properties discounted at 10%, from proved oil and gas reserves based on period-end prices and costs. Based on prices including hedging activities in effect on September 30, 2001 the Company would have had a non-cash ceiling test charge to earnings of approximately $60 million. However prices including hedging activities recovered significantly subsequent to September 30, 2001; and therefore as allowed by full cost accounting rules, no charge to earnings is deemed necessary at this time.

      On November 1, 2001 the Company sold its remaining interest in the Aconcagua field and related Canyon Express Pipeline System for $51 million. As a result of this sale, the Company's borrowing base under the Revolving Credit Facility was reduced from $80 million to $65 million.

3.      RELATED PARTY TRANSACTIONS

      Currently all of the Company's hedge positions are with Enron North America (ENA). In addition for the nine-months ending September 30, 2001 the Company has sold approximately 38% of its production to Enron North America or its affiliates. Related accounts receivables for production sold to ENA or its affiliates were $2.7 million at September 30, 2001. Production sales contracts are generally cancellable within three months. In the third quarter the Board of Directors approved a Service Agreement which allows ENA to be reimbursed for certain administrative functions provided on the Company's behalf.

4.      HEDGING PROGRAM

      On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, the Company uses only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in Other Comprehensive Income, a component of Stockholder's Equity, to the extent the hedge is effective.

      The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. The Company measures effectiveness on a period basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in accumulated Other Comprehensive Income related to cash flow hedges that become ineffective remain unchanged until the related production is delivered. If the Company determines that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.

      Gains and losses on hedging instruments when settled are included in natural gas or crude oil production revenues in the period that the related production is delivered.

      The following table sets forth the Company's position as of September 30, 2001:


Time Period

Notional
Quantities


Fixed Price


Fair Value

(in millions)
Natural Gas (MMBtu)
   October 1 - December 31, 2001
       Fixed price swap purchased774$2.180.0
       Fixed price swap purchased3,2184.437.1
   January 1 - December 31, 2002
       Fixed price swap purchased1,8312.18(1.2)
       Fixed price swap purchased12,1344.4318.5
   January 1 - December 31, 2003
       Fixed price swap purchased3,6503.742.0

Crude Oil

(MBbl)
   October 1 - December 31, 2001
       Fixed price swap purchased245$ 27.750.8
       Fixed price swap purchased9225.150.1
   January 1 - December 31, 2002
       Fixed price swap purchased36525.480.7
       Fixed price swap purchased18125.150.3
          Total$ 28.3

      Subsequent to September 30, 2001 the Company entered into a $3.03 average natural gas fixed prices swap for a notional quantity of 4,125 Mmbtu. The term of the agreement begins April 1, 2002 and ends December 31, 2002.

      On January 1, 2001, in accordance with the transition provisions of SFAS 133, the Company recorded $32.9 million in other comprehensive loss representing the cumulative effect of an accounting change to recognize at fair value all cash flow derivatives. The Company recorded cash flow hedge derivative liabilities of $32.9 million on that date. There is no tax effect on the cumulative effect.

      During the nine-months of 2001, settled hedging losses of $11.6 million were reclassed from Other Comprehensive Income to Revenue. As of September 30, 2001, the fair value of outstanding hedges was recorded as a deferred gain of $28.2 million in Other Comprehensive Income. As of September 30, 2001, the ineffective portion of the cash flow hedges were not material for the quarter.

      All hedge transactions are conducted pursuant to the Company's existing hedging policy or are approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

      The fair value of our hedging instruments was determined based on a broker's forward price quote and a NYMEX forward price quote. As of September 30, 2001, a commodity price increase of 10% would have resulted in an unfavorable change in fair value of $8.2 million and a commodity price decrease of 10% would have resulted in a favorable change in fair value of $8.2 million.

5.      COMMITMENTS AND CONTINGENCIES

     Litigation - The Company, in the ordinary course of business, is a claimant and/or a defendant in various legal proceedings, including proceedings as to which the Company has insurance coverage. The Company does not consider its exposure in these proceedings, individually and in the aggregate, to be material.

6.      EMPLOYEE REDUCTIONS

      During the third quarter, the Company reduced the number of employees at various levels. Severance and contract termination payments totaling $2.7 million were made as a result of these reductions.

7.      OTHER COMPREHENSIVE INCOME

      Other Comprehensive Income includes net income and certain items recorded directly to Stockholder's Equity and classified as Other Comprehensive Income. The Company recorded Other Comprehensive Income for the first time in the first quarter of 2001. Following the adoption of SFAS 133, the Company recorded an Other Comprehensive Income of $28.2 million related to the change in fair value of certain derivative financial instruments that has qualified for cash flow hedge accounting. The following table illustrates the calculation of Other Comprehensive Income:

Three-Months Ended
September 30, 2001
(In thousands)

Comprehensive
Income      
Other        
Comprehensive
Income      


Other comprehensive income - June 30, 2001$     $12,111
Net income$5,780

Other comprehensive loss
     Reclassification adjustment for settled contracts(2,557)
     Changes in fair value of outstanding hedged positions18,655

Other comprehensive loss16,09816,098

Comprehensive income$21,878


Other comprehensive loss$28,209


Nine-Months Ended
September 30, 2001
(In thousands)

Comprehensive
Income      
Other        
Comprehensive
Income      


Other comprehensive income - December 31, 2000$     --
Net income$37,724

Other comprehensive loss
     Cumulative effect of change in accounting principle - January 1, 2001(32,976)
     Reclassification adjustment for settled contracts11,587
     Changes in fair value of outstanding hedged positions49,598

Other comprehensive loss28,20928,209

Comprehensive income$65,942


Other comprehensive loss$28,209

There were no items in Other Comprehensive Income other than the Company's hedging activity.

8.      RECENT ACCOUNTING PRONOUNCEMENTS

      In July 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations" (effective July 1, 2001) and SFAS No. 142, "Goodwill and Other Intangible Assets" (effective on January 1, 2002). SFAS No. 141 prohibits pooling-of-interests accounting for acquisitions. SFAS No. 142 specifies that goodwill and some intangible assets will no longer be amortized but instead will be subject to periodic impairment testing. We do not believe the adoption of this statement will have an impact on our financial statements.

      In August and October 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" and SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets". SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement costs should be allocated to expense using a systematic and rational method. SFAS 143 is effective for fiscal years beginning after June 15, 2002. SFAS 144 addresses financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of", and is effective for fiscal years beginning after December 15, 2001. The company is currently assessing the impact of SFAS No. 143 and No. 144 and therefore cannot reasonably estimate the impact, if any, these statements will have on its financial statements upon adoption.

Independent Accountants’ Report



Board of Directors and Stockholder
Mariner Energy, Inc.
Houston, Texas



We have reviewed the accompanying condensed balance sheet of Mariner Energy, Inc. as of September 30, 2001 and the related condensed statements of operations for the three-month and nine-month periods ended September 30, 2001 and 2000 and the related condensed statements of cash flows for the nine-month periods ended September 30, 2001 and 2000. These condensed 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 auditing standards generally accepted in the United States of America, 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 condensed financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with auditing standards generally accepted in the United Sates of America, the balance sheet as of December 31, 2000, and the related statements of operations, stockholder’s equity, and cash flows for the year ended December 31, 2000 (not presented herein), and in our report dated April 2, 2001, 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, 2000 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 13, 2001

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, 2001 and 2000 should be read in conjunction with the condensed 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, 2000, filed with the Securities and Exchange Commission on April 2, 2001.

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, 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, capital resources, liquidity and other factors described in the Company's annual report on Form 10-K for the year ended December 31, 2000, filed with the Securities and Exchange Commission on April 2, 2001.

Results of Operations

The following table sets forth certain information regarding results of operations for the periods shown:

Three-Months Ended
September 30
Nine-Months Ended
September 30


2001   2000   2001   2000   




Total revenue, $MM$35.1$27.6$126.8$89.1
EBITDA(1), $MM23.319.693.566.2
Net income, $MM5.84.337.715.7
Production::
    Oil and condensate (Mbbls)7383142,2801,142
    Natural Gas (Mmcf)4,3606,60215,28521,584
    Natural Gas equivalents (Mmcfe)8,7888,48628,96528,438
Average realized sales prices::
    Oil and condensate ($/Bbl)$24.43$18.99$24.56$20.95
    Natural Gas ($/Mcf)3.913.284.633.02
    Natural Gas equivalents ($/Mcfe)3.993.264.383.13
Cash Margin(2) per Mcfe:
    Revenue (pre-hedge)$3.70$4.55$4.78$3.96
    Hedging impact0.29(1.29)(0.40)(0.83)
    Lease operating expenses(0.56)(0.52)(0.53)(0.45)
    Transportation(0.28)(0.27)(0.34)(0.19)
    Gross G&A costs(0.73)(0.34)(0.50)(0.36)




       Cash Margin$2.42$2.13$3.01$2.13




Capital Expenditures(3), $MM:
    Exploration:
       Leasehold and G&G costs$1.8$12.0$10.3$1.8
       Drilling6.79.337.511.6
    Development & other34.46.033.233.0
    Capitalized G&A and interest costs2.62.38.48.2




       Total$45.5$29.6$89.4$54.6




  1. EBITDA equals earnings before interest, income taxes, depreciation, depletion, and amortization. EBITDA should be used as a supplement to, and not as a replacement 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..

  2. 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 and / or spent by the company.

  3. Net of $39.5 million and $29.0 million of proceeds from property conveyances for the nine-month period ended September 30, 2001 and 2000, respectively. There were no conveyances made during the third quarter 2001.

Results of Operations for the Third Quarter of 2001

     Net production during the third quarter of 2001 was 8.8 billion cubic feet of natural gas equivalent (Bcfe) compared to 8.5 Bcfe during the same quarter of 2000.

     Hedging activities for the third quarter of 2001 increased our average realized natural gas and crude oil sales prices received by $0.55 per Mcf and $0.19 per Bbl and revenues by $2.4 million and $0.2 million, respectively. Hedging activities for the third quarter 2000 reduced our average realized natural gas and crude oil prices by $1.10 per Mcf and $11.85 per Bbl, resulting in reductions in revenue of $7.3 million and $3.7 million, respectively.

     Oil and gas revenues increased 27% to $35.1 million for the third quarter of 2001 from $27.6 million for the third quarter of 2000. The revenue increase reflected a 22% increase in realized prices, to $3.99 per Mcfe for the third quarter from $3.26 per Mcfe in the same period of 2000, in addition to an increase in production.

     Lease operating expenses increased 13% to $5.0 million for the third quarter of 2001, from $4.4 million for the third quarter of 2000, due to the addition of our Black Widow field located in Ewing Bank 966.

     Transportation expenses increased 11% to $2.5 million for the third quarter of 2001, from $2.3 million for the third quarter of 2000, due to the addition of our Black Widow field located in Ewing Bank 966.

     Depreciation, depletion, and amortization expense (DD&A) increased 22% to $15.6 million for the third quarter of 2001 from $12.8 million for the third quarter of 2000, as a result of an increase in the unit-of-production depreciation, depletion, and amortization rate to $1.78 per Mcfe from $1.51 per Mcfe.

     General and administrative expenses, which are net of overhead reimbursements received by us from other working interest owners, increased 220% to $4.3 million for the third quarter of 2001 from $1.4 million for the third quarter of 2000, due primarily to payments made to terminated employees.

     Interest expense for the third quarter of 2001 decreased 16% to $2.2 million from $2.6 million in the third quarter of 2000, due to the repayment of our revolving credit facility with proceeds from the sale of our Devils Tower field.

     Income before income taxes was $5.8 million for the third quarter of 2001 compared to $4.3 million in the third quarter of 2000.

Results of Operations for the First Nine Months of 2001

     Net production was 29.0 Bcfe for the first nine months of 2001 compared to 28.4 Bcfe for the same period of 2000. Total production for the full year of 2001 is expected to be approximately 36 Bcfe.

     Oil and gas revenues increased 42% to $126.8 million for the first nine months of 2001 from $89.1 million for the comparable period of 2000, primarily due to a 39% increase in realized prices to $4.38 per Mcfe in the first nine months of 2001 from $3.13 per Mcfe in the same period last year, and the production increases.

     Hedging activities for the first nine months of 2001 decreased our average realized natural gas sales price and increased our realized crude oil price received by $0.77 per Mcf and $0.07 per Bbl and revenues by $11.8 million and $0.2 million, respectively. Hedging activities for the first nine months of 2000 reduced our average realized natural gas and crude oil prices by $0.63 per Mcf and $8.66 per Bbl, resulting in reductions in revenue of $13.7 million and $9.9 million, respectively.

     Lease operating expenses increased 19% to $15.4 million for the first nine months of 2001, from $12.9 million for the comparable period of 2000, primarily due to the addition of our Black Widow field in Ewing Bank 966.

     Transportation expenses increased 83% to $9.9 million for the first nine months of 2001, from $5.4 million for the same period of 2000, due to the addition of our Black Widow field located in Ewing Bank 966 and a loss related to minimum gathering charges at our Pluto field.

     Depreciation, depletion, and amortization expense (DD&A) increased 19% to $49.8 million for the first nine months of 2001 from $41.7 million for the comparable period of 2000, as a result of the increase in the unit-of-production depreciation, depletion, and amortization rate to $1.72 per Mcfe from $1.47 per Mcfe.

     General and administrative expenses, which are net of overhead reimbursements received by us from other working interest owners, increased 74% to $8.0 million for the first nine months of 2001 from $4.6 million for the comparable period of 2000, due primarily to payments made to terminated employees.

     Interest expense for the first nine months of 2001 decreased 25% to $6.6 million from $8.8 million for the comparable period of 2000, primarily due to the repayment of our revolving credit agreement with proceeds from the sale of our Devils Tower field.

     Income (loss) before income taxes was $37.7 million income for the first nine months of 2001 compared to $15.7 million for the same period of 2000.

Liquidity, Capital Expenditures and Capital Resources

      As of September 30, 2001, we had a working capital deficit of approximately $23.6 million, compared to a working capital deficit of $24.5 million at December 31, 2000. Debt outstanding as of September 30, 2001 was approximately $99.8 million of senior subordinated notes. Following the sale of our Aconcagua field our borrowing base under the Revolving Credit Facility was decreased from $80 million to $65 million. As of September 30, 2001 we had no borrowings under the Revolving Credit Facility.

      Net cash provided by operating activities was $118.9 million in the first nine months of 2001, an increase of $82.3 million from the same period of 2000. This increase was attributable to an approximately $30.0 million increase in operating cash flow before changes in operating assets and liabilities due to higher production and higher commodity prices and an increase of $52.0 million in net cash caused by changes in working capital.

      Cash used in investing activities in the first nine months of 2001 increased to $89.4 million from $54.6 million for the same period in 2000 due primarily to higher exploration expenditures.

      Cash used by financing activities was $30 million for the first nine months of 2001 compared to cash provided of $22.4 million for the same period in 2000. In addition to cash from operating activities, for the first nine months of 2001 we received $39.5 million in proceeds from property conveyances, which was used to repay our $30 million 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 our 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 our 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,

20012000


Decrease in natural gas sales (in thousands)$(11,750)$(13,683)
Decrease in oil sales (in thousands)162(9,865)
Effect of hedging transactions on average natural gas sales price (per Mcf)(0.77)(0.63)
Effect of hedging transactions on average oil sales price (per Bbl)0.07(8.66)

      A table setting forth our open hedging positions as of September 30, 2001 is contained in footnote 4, "Hedging Program" of the condensed financial statements.

        Hedging arrangements for 2001 including hedges entered into after September 30, 2001, cover approximately 62% of our anticipated equivalent production for the year. Hedging arrangements for 2002 and 2003 cover approximately 52% and 5% of our anticipated equivalent production for those years, respectively.

        Based on prices including hedging activities in effect on September 30, 2001 the Company would have had a non-cash ceiling test charge to earnings of approximately $60 million. However prices including hedging activities recovered significantly subsequent to September 30, 2001; and therefore as allowed by full cost accounting rules, no charge to earnings is deemed necessary at this time.

        Capital expenditures for the first nine months of 2001 were $89.4 million including $8.4 million of capitalized general, administrative and interest costs and a deduction of $39.5 million for proceeds received from property conveyances, which was allocated to development expenditures. Fourth quarter capital expenditures are expected to be approximately $52 million before crediting the $51 million in proceeds received from sale of the Company’s interest in the Aconcagua field and related Canyon Express Pipeline System. Exploration and development capital expenditures are expected to be approximately $19 million and $33 million, respectively. The Company anticipates drilling two or more exploratory wells in the fourth quarter.

        On August 22, 2001 we were the apparent high bidder on 13 blocks offered in the Western Gulf of Mexico Lease Sale Number 180. All of these leases have subsequently been officially awarded by the MMS.

        We believe there will be adequate capital resources in order for us to fund our remaining planned activities in 2001. As an oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for natural gas, oil and condensate, which are dependent upon numerous factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and gas reserves that may be economically produced.In addition, depending on the levels of our cash flow and capital expenditures (the latter of which are, to a large extent, discretionary), we may need to refinance a portion of the principal amount of our senior subordinated debt at or prior to maturity. However, there can be no assurance that we would be able to obtain financing on acceptable terms to complete a refinancing.

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.

      Item 6. Exhibits and Reports on Form 8-K

     (a) None.

     (b) The Company filed no Current Reports on Form 8-K during the quarter ended September 30, 2001.



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 13, 2001/s/ Michael A. Wichterich

Michael A. Wichterich
Vice President of Finance
and Administration
(Principal Financial Officer and
Officer Duly Authorized to Sign
on Behalf of the Registrant)