Attached files
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| 8-K - FORM 8-K - Approach Resources Inc | d85464e8vk.htm |
| EX-99.1 - EX-99.1 - Approach Resources Inc | d85464exv99w1.htm |
Exhibit 99.2
| 3Q 2011 Quarterly Summary NOVEMBER 2, 2011 |
| Forward-looking 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 Wolffork shale resource play, estimated oil and gas in place and recoverability of the oil and gas, estimated reserves and drilling locations, capital expenditures, typical well results and well profiles, and production and operating expenses guidance included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. When used in this presentation, the words "will," "potential," "believe," "intend," "expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict," "project," "target," "profile," "model," or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. 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 for the year ended December 31, 2010. 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 Securities and Exchange Commission ("SEC") permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms "estimated ultimate recovery" or "EUR," reserve or resource "potential," "upside," "oil and gas in place" or "OGIP," "OIP" or "GIP," and other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. EUR estimates, potential drilling locations, resource potential and OGIP estimates have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Company's interest may differ substantially from our estimates. There is no commitment by the Company to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of the Company's ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, type/decline curves, per well EUR, OGIP and resource potential may change significantly as development of the Company's oil and gas assets provides additional data. Type/decline curves, estimated EURs, typical well related oil and gas in place, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, OGIP, recovery factors and costs prove correct. The Company has very limited production experience with these projects, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of resource potential, EURs and OGIP do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. IRR estimates assume NYMEX forward-curve gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs. Cautionary statements regarding oil and gas quantities |
| Approach Resources Inc. Notes: Proved reserves and acreage as of 6/30/2011 and 9/30/2011, respectively. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing price of $24.41 per share on 10/31/2011, plus net debt as of 9/30/2011. AREX OVERVIEW ASSET OVERVIEW Enterprise value $815.5 MM High quality reserve base 66.8 MMBoe proved reserves 97% Permian Basin 55% Oil & NGLs Permian core operating area 160,600 gross (142,000 net) acres 500+ MMBoe gross, unrisked resource potential Extensive inventory of drilling and recompletion opportunities Strong balance sheet to execute plan Borrowing base increased 30% to $260 MM from $200 MM |
| 3Q 2011 Financial Highlights Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2011 2011 2010 2010 Revenues ($M) $ 27,958 $ 14,916 Net income ($M) $ 7,073 $ 2,087 Net income per diluted share $ 0.25 $ 0.10 Adjusted net income (non-GAAP) ($M) $ 5,925 $ 2,293 Adjusted net income per diluted share $ 0.21 $ 0.11 EBITDAX (non-GAAP) ($M) $ 21,671 $ 11,628 EBITDAX per diluted share $ 0.76 $ 0.54 Notes: See "Adjusted Net Income" and "EBITDAX" reconciliation slides in appendix for reconciliation of adjusted net income and EBITDAX, respectively. |
| 3Q 2011 Operating Highlights Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2011 2011 2010 2010 Total production (MBoe) 612 418 Average daily production (MBoe/d) 6.7 4.5 Percent liquids 57% 34% Average realized price ($/Boe) $ 47.98 $ 39.54 Costs ($/Boe) Lease operating expense $ 5.82 $ 4.77 Production taxes 2.32 1.78 Exploration 3.22 1.36 General and administrative 6.18 7.68 DD&A 13.65 13.95 Notes: Realized price includes commodity derivatives. Production in Project Pangea running as planned Oil inventory build of ~29 MBbls through 3Q 2011 Inventory build reduced potential sales volumes by ~315 Bbls/d during 3Q 2011 Drilled 20 wells, completed 14 wells and recompleted 4 wells during 3Q 2011 Horizontal Wolfcamp and vertical Wolffork wells results continue to improve Horizontal Wolfcamp wells IP at 1,044 BOEPD - 798 BOEPD Vertical Wolffork recompletions average IP at 152 BOEPD Vertical Wolffork wells average IP at 140 BOEPD |
| Permian Basin - Operations Update Large, primarily contiguous acreage position 160,600 gross (142,000 net) acres (~76% NRI) Low acreage cost ~$350 per acre Low-risk, long-life reserve base 64.8 MMBoe proved reserves 57% liquids (51% proved developed) 3 operated drilling rigs 2 vertical rigs, 1 horizontal rig Vertical pilot program shifting to development stage 152 BOEPD average IP for 9 recent Wolffork recompletions (75% liquids) 140 BOEPD average IP for 7 recent vertical Wolffork wells (72% liquids) Note: other large independents with Wolffork / Wolfberry activities nearby include PXD, DVN and CXO |
| Wolffork Oil Shale Resource Play Sutton Crockett Irion Reagan Schleicher Pangea West Northern & Central Pangea 59,000 gross acres Continue pilot program Encouraging results from pilot wells 85,000 gross acres Begin vertical development Establish horizontal development Southern Pangea 18,000 gross acres 3-D seismic acquisition completed Begin horizontal drilling 1Q 2012 BAKER C 1201 CT B 1601 CT G 701H CT M 901H 54-13 1 45 D 901H 42-21 1H 45 E 1101H 45 B 2401H 45 A 701H Baker B 203 45 D 902H Chandler 4403 CT B 1303 Childress 603 Childress G 1008 42 B 1001H 45 C 803H ST 54-12 1 54-15 1 42-11 2R 42-23 9 Vertical Pilot - 2nd phase Horizontal Pilot Horizontal Drilling in Progress Drilling Depth to Top of Wolfcamp Legend Horizontal Waiting on Completion 54-9 1 54-19 3 54-2 1 54-15 2 54-16 3 CT B 1308 Baker A 114 West 2308 42-23 11 42-14 10 45 F 2301H 45 F 2302H 45 A 702H Horizontal Permitted Location 3-D seismic early-1Q 2012 |
| Horizontal Wolfcamp Well Performance RECENT HORIZONTAL WOLFCAMP RESULTS University 45 C 803H - 7,358' lateral, 23 frac stages Initial 24-hour flow rate 1,044 BOEPD, 95% liquids (931 BO, 57 Bbls NGLs, 335 MCFG) University 45 B 2401H - 7,613' lateral, 23 frac stages Initial 24-hour flow rate 811 BOEPD, 86% liquids (582 BO, 116 Bbls NGLs, 677 MCFG) University 45 D 902H - 7,770' lateral, 23 frac stages Initial 24-hour flow rate 798 BOEPD, 88% liquids (611 BO, 95 Bbls NGLs, 552 MCFG) Early 2011 9/2011 UPCOMING HORIZONTAL WOLFCAMP WELLS University 42 B 1001H - 7,769' lateral Targeting the Wolfcamp "C" zone University 45 E 1101H - 7,712' lateral University 45 F 2301H - 7,000'+ lateral CONSISTENTLY IMPROVING WELL RESULTS production (mboe/d) |
| 2011 Capital Budget 2011 Capital Budget $260 MM 2011 PROGRAM 2 Vertical rigs Expect to drill 58 vertical wells targeting the Wolffork or Canyon Sands (13 ahead of schedule) 1 Horizontal rig Expect to drill 13 horizontal Wolfcamp wells (2 ahead of schedule) 2 to 4 recompletions per month targeting the Wolffork oil shale Leasing activity and working interest acquisition expanded footprint in Wolffork oil shale play to 142,000 net acres, up from 101,000 net acres at YE 2010 Infrastructure projects will accommodate production in northeast Project Pangea and Block 45 |
| 2012 Capital Budget 2012 PROGRAM 2012 Capital budget $160 MM 2 Vertical rigs, 1 horizontal rig and 2 to 4 recompletions per month targeting the Wolffork oil shale Substantially same rig program as 2011 Targeting 20%+ production growth 2012 production guidance 2,800 MBoe - 3,000 MBoe Key takeaways: Initial 2012 capital program provides flexibility to develop Wolffork oil shale and monitor commodity prices and service costs Increase in liquids production drives expected increase in cash flow Increase in borrowing base strengthens liquidity |
| Production Outlook Liquids-Weighted Transformation 65% Liquids-weighted production mix in 2012 Targeting 20%+ production growth in 2012 98% Permian Basin PRODUCTION OUTLOOK production (mboe/d) percent liquids |
| 2011 Guidance 2011 Guidance 2011 Guidance 2011 Guidance 2012 Guidance Production Total (MBoe) 2,300 - 2,450 2,300 - 2,450 2,300 - 2,450 2,800- 3,000 Percent Oil & NGLs 55% 55% 55% 65% Operating costs and expenses ($/per Boe) Lease operating $ 5.00 - 6.00 5.00 - 6.00 5.00 - 6.00 $ 4.50 - 5.50 Severance and production taxes $ 2.35 - 3.00 2.35 - 3.00 2.35 - 3.00 $ 2.50 - 4.00 Exploration $ 4.00 - 5.00 4.00 - 5.00 4.00 - 5.00 $ 4.00 - 5.00 General and administrative $ 6.50 - 7.00 6.50 - 7.00 6.50 - 7.00 $ 5.25 - 6.25 Depletion, depreciation and amortization $ 12.00 - 15.00 12.00 - 15.00 12.00 - 15.00 $ 12.00 - 15.00 Capital expenditures ($MM) Approximately $260 Approximately $260 Approximately $260 Approximately $160 2011 & 2012 Operating and Financial Guidance Guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company's control. See slide 2, "Forward- looking statements," for additional information. |
| Natural gas (NYMEX - Henry Hub) 2011 Price swaps contracted for 230,000 MMBtu/month at $4.86/MMBtu June 2011 - December 2011 Price swaps contracted for 200,000 MMBtu/month at $4.74/MMBtu 65% of estimated 2011 natural gas production hedged at weighed average price of $4.82/MMBtu(1) Natural gas (WAHA - Basis Differential) 2011 Basis swaps contracted for 300,000 MMBtu/month at $(0.53)/MMBtu Oil (NYMEX - West Texas Intermediate) May 2011 - December 2011 Collars contracted for 1,000 Bbls/d Floor $100.00 - Ceiling $127.00 2012 Collars contracted for 700 Bbls/d Floor $85.00 - Ceiling $97.50 (1) Based on midpoint of 2011 production guidance. Hedge Position CURRENT HEDGE POSITION |
| Appendix NON-GAAP RECONCILIATIONS |
| (in thousands, except per-share amounts) Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2011 2011 2010 2010 Net income $ 7,073 $ 2,087 Adjustments for certain items: Unrealized (gain) loss on commodity derivatives (1,739) 312 Related income tax effect 591 (106) Adjusted net income $ 5,925 $ 2,293 Adjusted net income per diluted share $ 0.21 $ 0.11 The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. 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 SEC filings and posted on our website. Adjusted Net Income Reconciliation (Unaudited) |
| 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) gain on sale of oil and gas properties, (6) interest expense, and (7) 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. (in thousands, except per-share amounts) Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2011 2011 2010 2010 Net income $ 7,073 $ 2,087 Exploration 1,969 568 Depletion, depreciation and amortization 8,355 5,832 Share-based compensation 1,089 1,047 Unrealized (gain) loss on commodity derivatives (1,739) 312 Interest expense, net 1,016 615 Income tax provision 3,908 1,167 EBITDAX $ 21,671 $ 11,628 EBITDAX per diluted share $ 0.76 $ 0.54 EBITDAX Reconciliation (Unaudited) |
| Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company's ability to fund development and exploration activities. However, this measurement has limitations. This measurement can vary from year to year for the Company and can vary among companies based on what is or is not included in the measurement on a company's financial statements. This measurement 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. The table below summarizes our liquidity at September 30, 2011, and our liquidity position at September 30, 2011, reflecting the October 2011 borrowing base increase to $260 million from $200 million. Liquidity (Unaudited) (in thousands) Liquidity at September 30, 2011 Liquidity at September 30, 2011 Liquidity with Borrowing Base Increase at September 30, 2011 Liquidity with Borrowing Base Increase at September 30, 2011 Borrowing base $ 200,000 $ 260,000 Cash and cash equivalents 736 736 Outstanding letters of credit (350) (350) Long-term debt (122,000) (122,000) Liquidity $ 78,386 $ 138,386 |