Exhibit 99.1
Company December 2009 Presentation |
Forward-looking statements and cautionary statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including as to the Company's drilling program, estimated reserves and drilling locations, hedging activities, capital expenditures and financial and operating guidance included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's Annual Report on Form 10-K and Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission ("SEC") on March 13, 2009 and August 7, 2009, respectively. Any forward- looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 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. The Company uses the terms "estimated ultimate recovery," "EUR," "probable," "possible" and "resource" reserves, reserve "potential," "upside" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit the Company 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. December 2009 | 2 |
AREX overview Core areas of operation(1) (1)As of December 31, 2008, unless otherwise noted. (2)Based on November 30, 2009 closing price of $7.00 per share and 20.7 mm shares outstanding. (3)Net debt at September 30, 2009 was $36.2 mm. December 2009 | 3 Exchange/Ticker Market cap $145.2 mm(2) Enterprise value $181.4 mm(3) |
AREX investment highlights Peer comparison - EV/Mcfe ($/Mcfe)(2) (1)Long-term debt-to-capital ratio (a non-GAAP measure) definition provided on page 31. (2)Source: Tudor, Pickering, Holt & Co. Weekly Valuation Sheet, December 1, 2009, and AREX reports. Based on November 30, 2009 closing price of $7.00 per share, September 30, 2009 balance sheet and December 31, 2008 reported reserve estimates. December 2009 | 4 High quality, long-lived asset base to ride price cycles Low risk, repeatable, multi-year drilling inventory of over 1,200 identified locations Financial flexibility to reduce drilling in low-price environment in 2009 and pay down debt Strong balance sheet heading into 2010: $115 mm borrowing base $32.8 mm drawn at 11/30/2009 Long-term debt-to-capital ratio 14% at 9/30/2009(1) 2010 guidance midpoint of 25.1 MMcfe/d represents a 19% increase in production over October 2009 average daily production of 21.2 MMcfe/d Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development Attractive valuation versus peers: |
Proven track record Historic growth is organically driven Ozona Northeast historically represented majority of production and reserves Other development plays now contributing (Cinco Terry and North Bald Prairie) Flexibility to decrease capital expenditure budget and still achieve stable production in 2009 Proved reserves growth (Bcfe) Production growth (MMcfe/d) (1)Pro forma for the November 14, 2007 acquisition of Neo Canyon Exploration, L.P.'s 30% working interest in Ozona Northeast, as if the acquisition occurred on January 1, 2007. (2)Pro forma for the Neo Canyon acquisition. Observations December 2009 | 5 |
Reserve base and unrisked potential Reserve overview(1) (1)Estimates of proved, probable and possible reserves at December 31, 2008 are based on an independent engineering study of our oil and gas properties prepared by DeGolyer and MacNaughton. Resource reserve estimates are based on internal Company studies. Probable, possible and resource reserves are unrisked and unbooked. Proved reserve mix Total reserves by category Category Oil/NGLs (MBbls) Gas (MMcf) Equivalent (MMcfe) December 2009 | 6 |
Reserve growth at a low cost Drill-bit finding and development cost $2.11/Mcfe All-in finding and development cost, including revisions $2.64/Mcfe All-in finding and development cost, including revisions and change in future development costs $2.88/Mcfe Peer comparison: All-in F&D cost(1) Peer comparison: Drill-bit F&D cost(1) (1)Source: Tudor, Pickering, Holt & Co. small-cap peer group. Data from publicly-filed company reports. F&D costs (non-GAAP) reconciliation and important disclosures provided on pages 29-30. 2008 F&D cost metrics December 2009 | 7 |
LOE & severance tax(1) (1)Source: Tudor, Pickering, Holt & Co. small-cap peer group. LOE and severance tax data for the first 9 mos. of 2009 from publicly-filed company reports. Lease operating expenses include transportation expenses. December 2009 | 8 AREX: Low-cost producer |
Positioned to deliver value in 2010 December 2009 | 9 $53.0 mm capital budget 2010 guidance of 8,900 MMcfe - 9,400 MMcfe (midpoint 9,150 MMcfe or 25.1 MMcfe/d) 2010 midpoint represents a 19% increase in production over October 2009 average daily production of 21.1 MMcfe/d Allocating 86% of the 2010 capital budget to our low-risk, high-return core areas Ozona Northeast - $25.6 mm 2 rigs 36 gross (36 net) wells Cinco Terry - $19.9 mm 2 rigs 48 gross (24 net) wells 2010 program substantially funded with internally- generated cash flow 2010 Capital budget 2010 Program (1)Based on the midpoint of 2010 production guidance. See page 32 for hedging schedule. Hedging to secure capital 44% of total 2010 production hedged at a weighted average price of $6.18/Mcfe(1) |
Ozona Northeast Key highlights(1) Drilling inventory map(1) (1)As of September 30, 2009, unless otherwise noted. Canyon Sands tight gas, Strawn and Ellenburger development Own substantially all working interest in all depths 80% NRI Legacy asset with significant remaining development potential 144.4 Bcfe estimated proved reserves, 100% operated at 12/31/2008 Low decline rates (4%-6%) in mature wells 49,169 gross (43,180 net) acres Own or operate 140 miles of gathering lines 660 identified drilling locations at 12/31/2008 Evaluating reprocessed 3-D seismic to identify Strawn and Ellenburger targets December 2009 | 10 |
Ozona Northeast: typical Canyon well IRR Analysis (520 MMcfe EUR) Key observations Statistical, predictable results 520 - 480 MMcfe average gross EUR 396 - 366 MMcfe average net EUR (80% NRI) Premium price realization driven by high gas heat content 1,250 Btu per Mcfe Make-whole contract (wellhead) Contract expires 2/2011 Expected D&C costs $670k per well (8/8th) Expected breakeven at $3.50 NYMEX Decline curve Price (NYMEX), IRR & Payout Based on 520 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl December 2009 | 11 |
Cinco Terry Key highlights(1) Drilling inventory map(1) (1)As of September 30, 2009, unless otherwise noted. Canyon Sands tight gas development +-52% WI & 39% NRI Ellenburger development 45.9 Bcfe estimated proved reserves at 12/31/2008 48,893 gross (22,899 net) acres 456 identified drilling locations at 12/31/2008 Began 3-D seismic shoot Multiple horizon potential December 2009 | 12 |
Cinco Terry: 3-well cross section 3-Well cross section map December 2009 | 13 Baker B 201 University 45-29 1 University 42-13 5 |
Cinco Terry: 3-well cross section December 2009 | 14 Baker B 201 TD : 8,620' ELEV KB : 2,637' University 45-29 1 TD : 8,100' ELEV KB : 2,617' University 42-13 5 TD : 8,100' ELEV KB : 2,630' 12,469' 11,538' 6 16 CALI 0 200 GR 0.2 2,000 LLS 0.2 2,000 LLD 0.2 2,000 MSFL 0.3 - -0.1 DPHI 0.3 - -0.1 NPHI 0.2 2000 RT20 0.2 2000 RT30 0.2 2,000 RT60 0.2 2,000 RT90 0.3 DPHI 0.3 APF Ozone Top 7,700' 7,800' 7,900' 8,000' A' 6 16 CALI 0 200 GR 0.2 2,000 LLS 0.2 2,000 LLD 0.2 2,000 MSFL 0.3 - -0.1 DPHI 0.3 - -0.1 NPHI 6 16 CALI 0 200 GR - -0.1 - -0.1 7,700' 7,800' 7,900' 8,000' 7,700' 7,800' 7,900' 8,000' Sand Shale Gas-Filled Porosity Gas-Filled Porosity ~ 112' Gas-Filled Porosity ~ 120' Gas-Filled Porosity ~ 50' |
Cinco Terry: typical Canyon well IRR Analysis (547 MMcfe EUR) Key observations Decline curve Price (NYMEX), IRR & Payout Statistical results +-52% WI & 39% NRI 547 MMcfe average gross EUR 258 MMcfe average net EUR Premium price realization driven by high gas heat content 1,220 Btu per Mcfe 93% POP contract Expected D&C Costs $810k per well (8/8th) Expected breakeven at $3.00 NYMEX Based on 547 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl December 2009 | 15 |
Cinco Terry: typical Canyon/Ellenburger well Key observations Decline curve Statistical results +-52% WI & 39% NRI 653 MMcfe average gross EUR 311 MMcfe average net EUR Premium price realization driven by high gas heat content 1,220 Btu per Mcfe 93% POP contract Expected D&C costs $860k per well (8/8th) Expected breakeven less than $3.00 NYMEX IRR Analysis (653 MMcfe EUR) Price (NYMEX), IRR & Payout Based on 653 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl December 2009 | 16 |
Cinco Terry: Ellenburger upside Key observations Decline curve Statistical results +-52% WI & 39% NRI 1,315 MMcfe average gross EUR 670 MMcfe average net EUR Premium price realization driven by high gas heat content 1,220 Btu per Mcfe 93% POP contract Expected D&C costs $670k per well (8/8th) IRR Analysis (1,315 MMcfe EUR) Price (NYMEX), IRR & Payout Based on 1,315 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl December 2009 | 17 |
Cinco Terry Proposed 3-D seismic December 2009 | 18 |
North Bald Prairie Key highlights(1) Drilling inventory map(1) (1)As of September 30, 2009, unless otherwise noted. Cotton Valley Lime, Bossier Shale, Cotton Valley Sands development 50% WI & +-40% NRI 20.8 Bcfe estimated proved reserves at 12/31/2008 7,846 gross (3,240 net) acres Approximately 3,115 gross (2,026 net) acres have been re-leased at substantially 100% WI as of 11/30/2009 89 locations identified at 12/31/2008 Rodessa and Pettit behind pipe potential December 2009 | 19 |
North Bald Prairie: typical Cotton Valley well IRR Analysis (1,300 MMcfe EUR) Key observations Decline curve Price (NYMEX), IRR & Payout Statistical results 50% WI & +-40% NRI 1,300 - 1,000 MMcfe average gross EUR 507 - 400 MMcfe average net EUR Price realization 1,050 Btu per Mcfe Expected D&C costs $2.0 mm per well (8/8th) Based on 1,300 MMcfe average gross EUR December 2009 | 20 |
Exploratory plays Northern New Mexico - El Vado East British Columbia Western Kentucky - Boomerang 25% non-operated WI 31,231 gross (7,395 net) acres at 9/30/2009 Primary targets are Doig shale, Montney tight gas sands and lower Montney shale New Albany Shale 74,988 gross (44,759 net) undeveloped acres at 9/30/2009 Lease terms (1 year remaining primary + 5 year extensions remaining) provide option value on technology and gas prices After evaluating results from test wells, determine development program for the prospect Mancos Shale exploration 2,000 to 3,000 feet 90,357 gross (79,793 net) undeveloped acres at 9/30/2009 Proximity to several multi-million barrel fields (mostly crude oil) Additional prospectivity in Dakota, Morrison, Todilto and Entrada formations County ordinance finalized and drilling moratorium lifted 5/2009 Expect to begin drilling summer 2010 December 2009 | 21 |
AREX investment highlights (1)Long-term debt-to-capital ratio (a non-GAAP measure) definition provided on page 31. December 2009 | 22 2010 Outlook Focus on increasing production in core operating areas in the Permian Strategic acquisitions Bolt-on and PDP-weighted Opportunistic Balance cash flow with capital spending Increase 2010 - 2011 hedge position High quality, long-lived asset base to ride price cycles Low risk, repeatable, multi-year drilling inventory of over 1,200 identified locations Financial flexibility to reduce drilling in low-price environment in 2009 and pay down debt Strong balance sheet heading into 2010: $115 mm borrowing base $32.8 mm drawn at 11/30/2009 Long-term debt-to-capital ratio 14% at 9/30/2009(1) 2010 guidance midpoint of 25.1 MMcfe/d represents a 19% increase in production over October 2009 average daily production of 21.2 MMcfe/d Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development Attractive valuation versus peers |
Appendix |
Financial and operating guidance 2009 & 2010 financial and operating guidance The table below sets forth the Company's current 2009 and 2010 financial and operating guidance. The 2009 and 2010 guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company's control, as further described on page 2 of this presentation. December 2009 | 24 |
Equity ownership Ownership of management & certain beneficial owners at 9/30/2009 (1)As of most recent public filings, 1.9 million shares are owned by non-affiliate holders of 5% or more of our outstanding common stock. December 2009 | 25 |
Financial and operating data (unaudited) (1)EBITDAX (a non-GAAP measure) reconciliation provided on page 28. $ thousands, except per-unit metrics December 2009 | 26 |
Condensed balance sheet data (unaudited) $ thousands December 2009 | 27 |
EBITDAX reconciliation (unaudited) $ thousands, except per-share metrics We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized (gain) loss on commodity derivatives, (5) interest expense and (6) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. 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 GAAP (including the notes), included in our SEC filings and posted on our website. December 2009 | 28 |
Finding & development costs reconciliation (unaudited) We believe that providing measures of finding and development, or F&D, cost is useful to assist an evaluation of how much it costs the Company, on a per Mcfe basis, to add proved reserves. However, these measures are 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 GAAP (including the notes), included in our Annual Report on Form 10-K and Quarterly Reports on Form 10-Q filed with the SEC on March 13, 2009, May 6, 2009 and August 7, 2009, respectively. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases. As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company's future F&D costs will not differ materially from those set forth above. Further, the methods we use to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies. The following table reflects the reconciliation of our estimated finding and development costs for the year ended December 31, 2008 to the information required by paragraphs 11 and 21 of Statement of Financial Accounting Standard No. 69: December 2009 | 29 |
F&D costs reconciliation (unaudited) - cont. Drill-bit finding and development ("F&D") costs are calculated by dividing the sum of exploration costs and development costs for the year, by the total of reserve extensions and discoveries for the year. All-in F&D costs, including revisions, are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year, by the total of reserve extensions, discoveries, purchases and all revisions for the year. All-in F&D costs, including revisions and the change in future development costs, are calculated by dividing the sum of property acquisition costs, exploration costs, development costs and the change in future development costs from the prior year, by the total of reserve extensions, discoveries, purchases and all revisions for the year. Definitions Reconciliation (1) Includes $3.5 million in non-cash asset retirement obligations recorded in 2008. December 2009 | 30 |
Long-term debt-to-capital ratio (unaudited) Long-term debt-to-capital is calculated as of September 30, 2009, and by dividing long-term debt (GAAP) of $36.9 million by the sum of total stockholders' equity (GAAP) and long-term debt (GAAP) of $259.4 million. We use the long-term debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio has limitations. This ratio can vary from year to year for the Company and can vary among companies based on what is or is not included in the ratio on a company's financial statements. This ratio 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 GAAP (including the notes), included in our SEC filings and posted on our website. December 2009 | 31 |
Hedging positions as of 10/31/2009 2009 Natural gas hedges (1)Percent of estimated production hedged for 2009 is based on 1st 10 mos. of total 2009 production and the midpoint of 2009 production guidance, or 8,850 MMcfe. (2)Percent of estimated production hedged for 2010 is based on the midpoint of total 2010 production guidance, or 9,150 MMcfe. 2010 Natural gas hedges December 2009 | 32 We also have a basis swap at $(0.53) per MMBtu for 300,000 MMBtu per month for 2011. |