EX-99.1 2 a12-11276_3ex99d1.htm EX-99.1

Exhibit 99.1

 

Key Investment Highlights Large, Diversified Asset Base in Highest Return Resource Plays Large, contiguous operations in three of the highest return resource plays in the U.S. Diversification and acreage in each core area provides investment flexibility 59.3 MMBoe of proved reserves (59% oil / liquids; 44% PDP) across three areas Strong Cash Flow Generation Focused on Liquids-Rich, Low-Risk Basins Approximately 92% of 2012 drilling capital allocated to liquids targets Ability to generate robust IRRs across all plays Projected 2012 exit rate of 18,000 Boe/d with ~65% oil / liquids mix Increased Efficiency and Low Breakeven Economics LOE per Boe reduced ~55% from ~$21.90/Boe in 2010 to $9.78/Boe in Q1 2012 (1) Attractive 1Q 2012 cash margin of ~58% ($25.87/Boe) (1) Breakeven economics significantly below current commodity price levels in core focus areas Attractive Valuation / Asset Coverage MHR trades at only ~50% of pro-forma NAV Un-risked resource potential in excess of $8 billion NAV and PV-10% asset coverage of 6.1x and 2.3x, respectively Substantial liquidity pro-forma for offerings of more than $260 million Experienced Management and Operations Team 20+ years of individual industry experience Old Magnum Hunter sold to Cimarex in 2005 for $2.1 billion (average annual shareholder return of 38%) Track record of value creation at New Magnum Hunter Note: Refer to pages 54 and 55 for corresponding footnotes.

 


Bakken Results (*) Williston Basin Comparative Economics 25% 40% 37% 22% 25% 54% 27% 43% 44% 43% 37% $2.2 $8.0 $8.8 $9.6 $1.7 $ 7.0 $8.0 $6.9 $10.5 $3.4 $1.7 KOG MHR (North Dakota) MHR (Tableland) CLR DNR GEOI PXD CXO LPI MHR GEOI (1) (2) (3) (4) (7) (8) (9) (5) (10) (11) (6) Lower drilling and completion costs per well result in “best-in-class” returns even with lower EUR/well EUR/well (MBoe) 350 750 603 575 n/a 140 138 Wolfberry Results Well costs ($MM) IRR (%) Note: Refer to pages 54 and 55 for corresponding footnotes. (*) MHR’s IRRs and EURs based only on oil component of production (gas and gas liquids not included). Eagle Ford Results 325 300 433 185

 


24 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 $10.0 $11.0 $85.00 $90.00 $95.00 $100.00 $105.00 $110.00 $115.00 Economic Sensitivity of Eagle Ford – Gonzales County IRR: 38% IRR: 51% IRR: 63% IRR: 44% IRR: 54% IRR: 85% IRR: 97% CAPEX: $8.5MM + $0.3MM (ESP) + $.02MM PU IP-24 Hour: 1,250 Bbl/D EUR: 433 MBoe NPV-10 ($ MM) WTI Oil Price, $/Bbl Note: MHR currently receives an approximate $10 per barrel premium to WTI in the Eagle Ford.

 


34 Financial Strategy Financial Strategy Capital spending driven by rates of return across all operating areas • Capital budget adjusted in Q2 2012 to focus on high return, oil / liquids areas • Margins and EBITDAX projected to increase by year-end 2012 based on capital plan • Limited overhead expansion required to meet growth objectives Maintain conservative balance sheet • Continue to increase Senior Credit Facility borrowing base through reserves additions from organic growth to maximize liquidity • Simplify balance sheet over time • Target Net Debt / Last-Quarter-Annualized EBITDAX of ~2x by year-end 2012 • Utilize equity, both common and preferred, when appropriate to maintain conservative financial ratios • Maintain liquidity to provide capital cushion and for opportunistic expansion Maintain an active hedging program to support economic returns and ensure strong coverage metrics • Target rolling 50% hedging program one to two years forward – will hedge further opportunistically • Hedges in place, up to the current maximum allowable volumes under the credit agreement for natural gas in 2012 and 2013, provide ~$4/MMBtu on ~67% of estimated 2012 production

 


36 Operating and Credit Statistics Operating and Credit Statistics 2011 Q1 2012 Q4 2012E ($ in millions, except per unit data) Actual Pro Forma Production: Average Daily Production (1) 5,510 13,700 ~17,000 % oil / liquids (1) 43% 40% 65% % change vs. PF Q1 2012 24% 2012E Exit Rate ~18,000 Illustrative Reserves: Total Q2-Q4 2012 E&P Drilling Capex $279.5 Assumed Drillbit F&D cost ($/Boe) (2) $10.90 $11.00 Implied Reserve Additions (MMBoe) 25.4 Less: Q2-Q4 Production (MMBoe) (1) (4.1) Illustrative Proved Reserves (MMBoe) (3) 44.9 59.3 80.7 % change vs. PF Q1 2012 35% Net Debt (4) $253.5 $418.9 $418.9 Illustrative Leverage Statistics: Illustrative Net Debt / Proved Reserves ($/Boe) $7.06 $5.19 % change vs. PF Q1 2012 (26%) Note: Refer to pages 54 and 55 for corresponding footnotes.

 


37 Strong Pro Forma Collateral Coverage $517 $517 $441 $797 $441 $299 $1,305 $991 3/31/12 1P PV-10% (NYMEX) Enterprise Value Total NAV (based on undeveloped acreage) $1,789 $958 $2,562 Coverage Proved Undeveloped Proved Developed 2.3x 6.1x 4.3x Residual Eureka Hunter Value (2) Total Undeveloped Acreage Value (3) Pro-forma Net Debt: $418.9 MM ($ in millions) Note: Refer to pages 54 and 55 for corresponding footnotes. PF Corporate adjustments PF Market Value MHR's Market Value represents ~50% discount to its NAV estimate (1)

 


54 Page 2 • (1) Management guidance for 2012 exit production oil / liquids mix. Page 3 • (1) Based on approximately 35 million shares at 5/2/2012 closing price. Page 7 • (1) 184 Bbl/d is frac’d waiting on drill out and equipping, and approximately 177 Bbl/d is behind pipe or drilling. Page 9 • (1) Includes acquisitions and capex. • (2) Triad acquisition totaled $81MM; $10MM of value was allocated to Eureka Hunter. • (3) Not pro-forma for the Baytex acquisition. Page 10 • (1) Based on North Dakota (2 mile lateral) type well and $90.00/Bbl realized price. • (2) Based on Saskatchewan (1 mile lateral) type well and $90.00/Bbl realized price. • (3) Based on mid-case for Gonzales County type well, $10.00/Bbl positive differential to $90/Bbl realized price. • (4) Based on mid-case Marcellus type curve, $2.5/MMBtu natural gas, $85.00/Bbl oil and $53.29/bbl NGL pricing (63% of oil). Page 11 • (1) Based on North Dakota (2 mile lateral) type well and $90.00/Bbl realized price. • (2) Based on Saskatchewan (1 mile lateral) type well and $90.00/Bbl realized price. • (3) Based on mid-case for Gonzales County type well, $10.00/Bbl positive differential to $90/Bbl realized price. • (4) Based on mid-case Marcellus type curve, $2.5/MMBtu natural gas, $85.00/Bbl oil and $53.29/bbl NGL pricing (63% of oil). Page 12 • (1) Not pro-forma for Baytex acquisition. Page 16 • (1) Undeveloped acreage value not associated with proved reserves. Page 19 • (1) Based on $85.00/Bbl WTI and $10.00/Bbl positive differentials to WTI, as per KOG April 2012 IR presentation. • (2) Based on North Dakota (2 mile lateral) type well and $90.00/Bbl realized price, based only on oil content (gas and gas liquids not included), as per MHR’s management estimates. • (3) Based on Saskatchewan (1 mile lateral) type well and $90.00/Bbl realized price, based only on oil content (gas and gas liquids not included), as per MHR’s management estimates. • (4) Based on single well, $90.00/bbl oil net of differentials and $4.50/MMBtu natural gas, as per CLR March 2012 presentation. • (5) Based on 20% Royalty, $21.00/well F&D, operating cost of $8.00/Bbl, $90.00/Bbl WTI and $10.00/Bbl positive differentials to WTI, as per DNR May 2012 IR presentation. • (6) Based on $90.00/Bbl oil and $4.50/Mcf natural gas, as per GEOI March 2012 IR presentation. • (7) Based on $100.00/Bbl oil and $4.00/Mcf natural gas, as per PXD May 2012 IR presentation. • (8) Based on 40-acre spacing, $90.00/Bbl oil and $4.00/Mcf natural gas, excluding interest, federal and state taxes, G&A, land cost and hedges, as per CXO May 2012 IR presentation. • (9) Based on 40-acre spacing, $90.00/Bbl oil and $4.00/Mcf natural gas, as per LPI April 2012 IR presentation. • (10) Based on mid-case for Gonzales County type well, $90/Bbl WTI price and $10.00/Bbl positive differential to WTI, as per MHR’s management estimates. • (11) Based on $90/Bbl oil and $4.5/Mcf natural gas, as per GEOI March 2012 IR presentation. Page 28 • (1) Assumes $85.00/Bbl for oil and NGL pricing of $53.29/Bbl (63% of oil) Page 32 • (1) Initial investment of $106.8 million, ~$60 million to the parent, MHR; remaining $46.8 million to fund the cash portion of the TransTex acquisition. • (2) TransTex acquisition completed for $58.5 million. $46.8 million cash portion funded via ArcLight investment. Other footnotes Source: Company information and Management estimates, unless stated otherwise. Note: Unless otherwise stated, market data as of 5/2/2012, Proved Reserves and PV-10 figures based on SEC pricing ($98.15/Bbl and $3.71/MMBtu) as of 3/31/12; all numbers are pro-forma for Baytex acquisition, $450 million debt financing and expected equity issue; Magnum Hunter is a successful efforts method of accounting company.

 


55 Page 35 • (1) Excludes $0.786 million of cash held by and only available to Eureka Hunter. • (2) Includes unrestricted subsidiaries notes payable. • (3) Excludes Eureka Hunter’s $46.0 million second lien term loan. • (4) Excludes Eureka Hunter’s $58.1 million preferred stock. • (5) Adjustment for net proceeds of equity offering based on approximately 35 million shares at 5/2/2012 closing price. • (6) Represents LQA MHR EBITDA (pro-forma for Eagle Operating and excluding TransTex Gas Services) for Status Quo and LQA MHR EBITDA plus LQA Baytex EBITDA for Pro-Forma. Page 36 • (1) Q2-Q4 production and % oil / liquids based on management estimates. • (2) F&D costs defined as total exploration and development costs divided by reserves additions from extensions, discoveries, revisions and other additions, excluding all acquisitions and assets retirement obligations. • (3) Q4 2012E calculated based on 3/31/12 pro forma balance plus additional reserves determined by dividing drilling capex by assumed F&D cost minus Q2-Q4 2012E production. • (4) For illustrative purposes, assumes pro forma net debt at Q4 2012 is unchanged from Q1 2012 level. Not including Eureka Hunter non-recourse debt. Page 37 • (1) Based on pro forma consolidated capitalization and implied equity value assuming 5/2/2012 closing price and pro forma shares outstanding. • (2) Based on residual equity value associated with MHR’s 72% ownership of its unrestricted subsidiary Eureka Hunter, as implied by the recent ArcLight transaction. • (3) For Eagle Ford, based on 19,640 net undeveloped acres x $25,000/acre. For Triad Hunter, based on 54,586 net undeveloped Marcellus acres x $7,500/acre and 61,151 net undeveloped Utica acres x $4,000/acre. For Williston, based on implied value of undeveloped acreage acquired with Baytex acquisition. Page 38 • (1) Borrowing base decrease of $0.30 per each $1.00 of debt, related to the existing new $100 million Term Loan Facility. • (2) Borrowing base decrease of $0.25 per each $1.00 of debt related to the new $450 million of Unsecured Notes. Page 39 • (1) 2010 and 2011 based on total exploration and development costs divided by reserve additions from extensions, discoveries, revisions and other additions, excluding all acquisitions and asset retirement obligations; Q1 2012 assumed at $11.00/Boe, in line with 2011. Page 45 • (1) Calculation based on weighted average shares outstanding on annual basis. Page 46 • (1) Assumes flat $3.50/MMBtu for natural gas • (2) Assumes flat $95.00/Bbl for oil and $3.50/MMBtu for natural gas • (3) Price required to achieve 10% IRR • (4) Assumes flat $85.00/Bbl for oil and NGL pricing of $53.29 (63% of oil) Page 52 • (1) Triad acquisition totaled $81MM; $10MM of value was allocated to Eureka Hunter. • (2) Includes acquisitions and capex. • (3) As of 3/31/2012; Based on SEC pricing. • (4) Eureka Hunter distributions of $20MM from Eureka Credit Facility and $60MM from ArcLight transaction. • (5) Eagle Ford: 19,640 net undeveloped acres x $25,000/acre; Triad Hunter: 54,586 net undeveloped Marcellus acres x $7,500/acre and 61,151 net undeveloped Utica acres x $4,000/acre. • (6) Based on ArcLight transaction. Page 53 • (1) Vast majority of other subsidiaries 100% owned by MHR except PRC Williston, LLC which is 100% owned by Magnum Hunter. Other footnotes (cont Other footnotes (cont’d) d) Source: Company information and Management estimates, unless stated otherwise. Note: Unless otherwise stated, market data as of 5/2/2012, Proved Reserves and PV-10 figures based on SEC pricing ($98.15/Bbl and $3.71/MMBtu) as of 3/31/12; all numbers are pro-forma for Baytex acquisition, $450 million debt financing and expected equity issue; Magnum Hunter is a successful efforts method of accounting company.