JP Morgan High Yield and Leveraged Finance Conference

Transcription

1 JP Morgan High Yield and Leveraged Finance Conference February 2, 2009

2 Disclosure This presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of All statements, other than statements of historical facts, that address activities that Mariner assumes, plans, expects, believes, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. Our forward-looking statements generally are accompanied by words such as may, will, estimate, project, predict, believe, expect, anticipate, potential, plan, goal, or other words that convey the uncertainty of future events or outcomes. Such forward-looking statements, which include our guidance estimates, involve known and unknown risks, uncertainties and other factors that may cause Mariner s actual results or plans to differ materially from those in the forward-looking statements. There can be no assurance that any guidance estimates can or will be achieved. The forward-looking statements made in this presentation are based on Mariner s current beliefs based on currently available information and assumptions that Mariner believes are reasonable. Mariner does not undertake any obligation to update estimates or other forward-looking statements as conditions change or additional information becomes available. Investors are urged to read the Annual Report on Form 10-K for the year ended December 31, 2007 and other documents filed by Mariner with the Securities and Exchange Commission ( SEC ) that contain important information including detailed risk factors. The SEC has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Mariner uses the terms probable, possible and non-proved reserves, reserve potential or upside or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC s guidelines may prohibit it from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company. Unless otherwise stated, all well information in this presentation is presented on a gross or 8/8th s basis and all production is presented net to Mariner s revenue interest. This presentation does not constitute an offer to sell or a solicitation of an offer to buy any securities of Mariner. About the cover: At left Viking Drilling Company s Viking No. 3 rig drilling on Mariner s Spraberry acreage. At right Diamond Offshore s Ocean America on location for Mariner in the deepwater Gulf of Mexico. 2

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4 Mariner s Portfolio Strategy INTEGRITY BALANCE EFFICIENT GROWTH OPPORTUNITY Expand Deepwater Pursue high-impact exploration projects leveraging the company s successful track record in deepwater exploration and development Expand Onshore Focus primarily in the Permian Basin but also pursuing other basins that provide relatively low-risk, repeatable projects Exploit Shelf Assets Increase production and generate excess cash flow 4

5 Mariner s Senior Notes Two Tranches of Debt Issued in Registered Transactions $300 million principal amount of 7 ½% Senior Notes due 2013 Interest payable on April 15 and October 15 of each year Mature on April 15, 2013 $300 million principal amount of 8% Senior Notes due 2017 Interest payable on May 15 and November 15 each year Mature on November 15, 2017 A summary of the indentures governing the notes is included on pages 52 to 54 and 81 to 82 of Mariner s K. * 8 % Senior Notes Due 2017 CUSIP = 56845T AF 4 7½ % Senior Notes Due 2013 CUSIP = 56845T AE 7 5

6 Striking the Balance Moderate-Risk Profile With Significant Upside Potential 6

7 Reserves Integrity and Balance Proved Reserves Fully Engineered by Ryder Scott Company Proved: 836 Bcfe At 12/31/07 Probable: 403 Bcfe* At 12/31/07 15% 39% 46% 53% 26% 21% Shelf Deepwater West Texas Shelf Deepwater West Texas Balanced Reserve Base Approximately 54% natural gas and 46% oil, NGLs and condensate PUDs only 33% of proved reserves Track record of significant probable to proved conversions * Approximately 50% of probable reserves have been engineered by Ryder Scott. 7

8 Strong Track Record of Growth Balanced Proved Reserve Expansion Average Daily Production Rate Bcfe 1, West Texas Deepwater Shelf 52% CAGR MMcfe/d E 2009G 39% CAGR 8

9 Efficient Growth Mariner Cost-Effectively Replaced Production, Increased Reserves Three-Year Reserve Replacement Rate* Three-Year Reserve Replacement Cost* % $/Mcfe * See appendix for calculations of reserve replacement rate and reserve replacement cost. 9

10 2009 Capital Investment Program Operating CAPEX Estimated at $430 million* By Region By Category 44% 48% 47% 45% 9% Shelf Deepwater West Texas 8% Exploration Development Other Major CAPEX Components $104 million deepwater exploration program ~5 wells including 3 subsalt $68 million shelf exploration program ~7 wells including 1-2 deep shelf $176 million development program deepwater and shelf $32 million West Texas drilling program ~30 wells * Excludes acquisitions and reimbursable hurricane-related expenditures, as well as capitalized corporate items and GG/leasehold/rentals 10

11 Gulf of Mexico: Deepwater and Shelf Exploration and Development

12 GOM Drilling Record 1/04 thru 12/08 Wells Drilled wells drilled with 64% success rate 64% 68% 80% 20 53% 15 42% Successful Wells Unsuccessful Wells 12

13 Exposure to All Play Types in the Deepwater Gulf of Mexico Opportunity Rich; Multi-Play, Multi-Trap; ~50 Bcfe to >1 Tcfe Targets More than 50 Prospects With ~5 Tcfe in Net Potential Conventional Amplitude Subsalt Overhang Subsalt Expanded Miocene Lower Tertiary (Wilcox) 13

14 Deepwater Exploration 28 Blocks Awarded in Lease Sales 205 and 206 Since the mid-1990s, Mariner has participated in the discovery of more than 2 Tcfe of gross proved and probable reserves in the deepwater Gulf of Mexico 14

15 Deepwater Catalysts Drilling Candidates Over Next Three Years Conventional DW Amplitude Salt Overhang Subsalt Expanded Miocene Lower Tertiary Estimated Size (Bcfe) ,200+ 1,000+ Estimated Dry Hole Costs (gross, $MM) Target W.I. (%) <50 <25 <25 Estimated Development Costs (gross, $MM) , ,500 Current Mariner Prospects ARDEN BUSHWOOD CAIMAN CROC RICHLAND BLUTO CUTTER CLINTON MANDY MAGELLAN #3 RIGEL #2 ZLOTY #2 BASS LITE #3 GEAUXPHER #4, #5 ATRIP BACKSLICE BIMINI EAGLE NEST LARISSA SALT BRANCH TOP MAST BOONVILLE HEIDELBERG YKK DEEP SANTA RITA OWL CREEK FROSA FASTRILL 2009 Prospects Prospects 15

16 Solid Deepwater Foundation Developments in Progress, Robust Prospect Inventory (>5 Tcfe) GROWTH POTENTIAL 2006: 58 MMcfe/d 2007: 69 MMcfe/d 1H 2008: 140 MMcfe/d 16

17 Deepwater Growth Continues Developments Underway at Garden Banks 462 (Geauxpher), Viosca Knoll 821 and Green Canyon 646 (Daniel Boone) 17

18 Shelf Strategy Since 2006, Mariner s Shelf Assets Have Created More Than $300 Million In Excess Cash Flow Perform detailed field studies 380 Bcfe identified 100% success on 22 projects to date Production up 65% since recompletions Continue intensive exploration program Achieve economies of scale Unmanned platforms Optimized loops 18

19 Robust Shelf Opportunities Extensive Exploration, Exploitation and Workover Portfolio 2006: ~132 MMcfe/d GROWTH POTENTIAL 2007: ~182 MMcfe/d 1H 2008: ~218 MMcfe/d 19

20 Near Term Shelf Exploitation Projects Numerous Moderate-Risk, High-Return Potential Reserve Additions 20

21 Permian Basin Expansion

22 Successful Five-Year Growth Initiative Permian Basin Proved Reserves Permian Basin Acreage Bcfe % CAGR Net Acres 110, , ,000 90,000 80,000 70,000 64,377 60,000 50,000 40,000 31,199 31,845 30,000 20,000 14,226 10, % CAGR 22

23 Permian Basin Expansion ~375 PUDs, >1,000 Potential Locations 23

24 Mariner s Value Proposition INTEGRITY BALANCE EFFICIENT GROWTH OPPORTUNITY Targeting 20% growth in 2009, following expected double digit growth in 2008 even with hurricane disruptions and 25% growth in 2007 Deepwater exploration provides substantial potential upside Expanding Permian Basin asset base provides stability and liquidity Large underexploited shelf portfolio provides significant excess cash flow from moderate-risk projects 2009 is expected to be another strong year 24

25 Appendix

26 Reconciliation of Non-GAAP Measure EBITDA means earnings before interest, income taxes, depreciation, depletion, amortization and impairments. Mariner believes that EBITDA is a widely-accepted financial indicator that provides additional information about its ability to meet its future requirements for debt service, capital expenditures and working capital, but EBITDA should not be considered in isolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles (GAAP) or as a measure of a company's profitability or liquidity. The 2008 illustration of EBITDA is based on previously disclosed production and cost guidance provided in February Pricing assumes actual January-September NYMEX settlements and three months NYMEX strip at 10/03/08. Actual results may vary significantly based on operational performance and price realizations EBITDA Reconciliation Net income (GAAP) + Net interest expense + Provision for income taxes + Depreciation, depletion and amortization EBITDA (Non-GAAP) (In thousands) $ 40,481 $ 121,462 $ 143,934 8,172 39,649 54,665 21,294 67,344 77,324 59, , ,321 $ 129,416 $ 520,635 $ 660,244 EBITDA for 2005, 2006 and 2007 includes $25.7MM, $10.2MM and $10.9MM of non-cash stock compensation expense, respectively. 26

27 Reconciliation of Non-GAAP Measure Operating cash flow ( OCF ) is not a financial or operating measure under GAAP. The table below reconciles OCF to related GAAP information. We believe that OCF is a widely-accepted financial indicator that provides additional information about our ability to meet our future requirements for debt service, capital expenditures and working capital, but OCF should not be considered in isolation or as a substitute for net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP or as a measure of our profitability or liquidity. The 2008 illustration of OCF is based on production and cost guidance. Pricing assumes actual January-September NYMEX settlements and three months NYMEX strip at 10/03/08. Actual results may vary significantly based on operational performance and price realizations. Years Ended December (In thousands) Cash flow from operating activities (GAAP) $ 536,113 $ 277,191 $ 165,444 Changes in operating assets and liabilities 86, ,217 (15,458) Operating cash flow as presented (Non-GAAP) 622, , ,986 Weighted average shares outstanding diluted 86,126 76, ,766.6 Operating cash flow per fully diluted share $ 7.23 $ 6.38 $

28 Calculation of Reserve Replacement Rate Natural Gas Oil Natural Gas Equivalent (Mbbl) (MMcf) (MMcfe) RRR 31-Dec-02 11, , ,165 Revisions of previous estimates 900 (3,076) 2,324 Extensions, discoveries and other additions 2,795 62,609 79,379 Purchases of reserves in place Sales of reserves in place (34) (44,233) (44,437) Production (1,600) (23,771) (33,371) 31-Dec-03 13, , , % Revisions of previous estimates 1,249 19,797 27,291 Extensions, discoveries and other additions 2,225 28,334 41,684 Purchases of reserves in place Sales of reserves in place Production (2,298) (23,782) (37,570) 31-Dec-04 14, , , % Revisions of previous estimates ,971 Extensions, discoveries and other additions 1,167 22,307 29,309 Purchases of reserves in place 7,181 50,837 93,923 Sales of reserves in place Production (1,791) (18,354) (29,100) 31-Dec-05 21, , , % Revisions of previous estimates 8,685 (58,055) (5,947) Extensions, discoveries and other additions 9,823 93, ,050 Purchases of reserves in place 12, , ,201 Purchase FST Acquisition 298,200 Purchase less FST Acquisition 21,001 Sales of reserves in place (354) (4,733) (6,857) Production (4,075) (56,064) (80,512) 31-Dec-06 48, , , % Revisions of previous estimates 5,707 2,402 36,643 Extensions, discoveries and other additions 4,671 61,548 89,576 Purchases of reserves in place 11,763 25,832 96,407 Sales of reserves in place (283) (341) (2,041) Production (5,431) (67,689) (100,273) 31-Dec-07 64, , , % Reserve replacement rate (RRR) for a period is calculated by dividing the sum of total reserve extensions, discoveries and other additions, revisions and purchases (i.e. acquisitions) by production for the same period. The proved reserves attributable to a 2006 acquisition were excluded from the calculation in 2006 to reflect more accurately Mariner's ongoing operational performance. 3-yr Revisions 35,586 3-yr Extensions, discoveries and other additions 150,372 3-yr Purchases of reserves in place 93,923 3-yr Rolling RRR 3-yr Production (100,041) % 3-yr Revisions 27,315 3-yr Extensions, discoveries and other additions 223,043 3-yr Purchases of reserves in place (less FST Acquisition) 114,923 3-yr Production (147,182) % 3-yr Revisions 36,667 3-yr Extensions, discoveries and other additions 270,935 3-yr Purchases of reserves in place (211,331) 3-yr Production (209,885) % 28

29 Calculation of Reserve Replacement Cost Reserve replacement cost (RRC) is calculated by dividing development, exploitation, exploration and acquisition capital expenditures, reduced by proceeds of divestitures, for the period by net estimated proved reserve additions for the period from all sources, including acquisitions and divestitures. Our calculation of reserve replacement cost includes costs and reserve additions related to the purchase of proved reserves. The methods we use to calculate our reserve replacement cost may differ significantly from methods used by other companies to compute similar measures. As a result, our reserve replacement cost may not be comparable to similar measures provided by other companies. We believe that providing a measure of reserve replacement cost is useful in evaluating the cost, on a per-mcfe basis, to add proved reserves. However, this measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with generally accepted accounting principles. Due to various factors, including timing differences in the addition of proved reserves and the related costs to develop those reserves, reserve replacement costs do not necessarily reflect precisely the costs associated with particular reserves. As a result of various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, we cannot assure you that our future reserve replacement costs will not differ materially from those presented. Reserve Replacement Cost Capital costs related to property acq, expl, and devel Installation of Aldwell unit gathering system Hurricane Repairs (16.359) Proceeds from divestitures CAPEX (before divestitures) Revisions of previous estimates (5.947) Extensions, discoveries and other additions Purchases of reserves in place Reserve additions (Bcfe) Reserve Replacement Cost/Mcfe $2.16 $1.96 $3.79 $3.49 Rolling 3-year average CAPEX , , Rolling 3-year average reserve additions Rolling 3-year average Reserve Replacement Cost/Mcfe $1.77 $1.73 $2.83 $

30 2009 Hedging Program Natural Gas Average MMBtu/D 180, , , , ,000 80,000 60,000 40,000 20,000 Oil 0 Average Bbl/D 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 $7.68 $7.48 $7.60 $7.65 1Q09 2Q09 3Q09 4Q09 $76.27 $76.27 $76.11 $ Q09 2Q09 3Q09 4Q09 Summary Hedges to date represent ~42% of production at mid-point of guidance ( Bcfe). ME does not have any production hedged beyond Quantity Wtd. Ave. Period MMBtu Price 1Q09 14,383, Q09 14,703, Q09 12,014, Q09 10,205, TOTAL 51,307,084 $7.60 Quantity Wtd. Ave. Period BBl Price 1Q09 633, Q09 569, Q09 512, Q09 456, TOTAL 2,172,210 $

31 Mariner s Secured Bank Credit Facility Borrowing Base Reaffirmed at Existing Level in December 2008; Scheduled for Next Review in February 2009 In January 2008, maximum credit availability increased to $1 billion, subject to a borrowing base In June 2008, borrowing base increased to $850 million Financial covenants: Maintain a ratio of consolidated current assets plus unused borrowing base to consolidated current liabilities of at least 1:1 Maintain a ratio of total debt to EBITDA of not more than 2.5:1 Standard & Poor s currently rates Mariner Energy at B+; Moody s Investor Services rates the company at B3 31

32 Mariner Energy s Bank Group Long-Term, Multi-Transactional Relationships Often Involving More Than Credit Facility Counterparty Business Lender Union Bank of California, N.A. BNP Paribas BMO Capital Markets Financing, Inc. Guaranty Bank JP Morgan Chase Bank, N.A. Calyon New York Branch Citicorp USA, Inc. The Bank of Nova Scotia Wells Fargo Bank, National Association Comerica Bank Natixis Bank of Scotland plc Capital One, N.A. DZ Bank AG Deutsche Zentral Genossenshaft Frankfurt am Main, New York Branch Wachovia Bank, National Association Amegy Bank National Association Frost National Bank Total Tranche A Commitment $89,607, $89,607, $86,470, $80,000, $80,000, $60,000, $52,941, $60, $60,000, $47,058, $53,333, $38,235, $43,333, $38,235, $43,333, $41,176, $36,666, $1,000,000,