INVESTOR PRESENTATION OCTOBER 2012 Exhibit 99.1 |
Forward Looking-Statements 2 Cautionary Statements Regarding Oil & Gas Quantities 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 resource potential and recoverability of the oil and gas, estimated reserves and drilling locations, capital expenditures, typical well results, and well profiles, type curve, 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 most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. 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,” 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 and resource potential 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 the Company’s 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, as well as geological and mechanical factors Estimates of unproved reserves, type/decline curves, per well EUR and resource potential may change significantly as development of the Company’s oil and gas assets provides additional data. Type/decline curves, estimated EURs, resource potential, 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, 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 and EURs do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. Unless otherwise noted, IRR estimates are before taxes and assume NYMEX forward-curve oil and 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. |
Notes: Proved reserves and acreage as of 6/30/2012. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing share price of $30.06 per share on 9/27/2012, plus estimated net debt as of 9/30/2012. Company Overview • Enterprise value $1.2 BN • High quality reserve base • Permian core operating area 166,000 gross (146,000 net) acres 500+ MMBoe gross, unrisked resource potential 2,900+ drilling and recompletion opportunities • Oil-driven growth in Q2 2012 Q2’12 Production 7.7 MBoe/d, 65% oil & NGLs Q2’12 Revenue mix 64% oil, 25% NGLs and 11% natural gas 3 AREX OVERVIEW ASSET OVERVIEW 83.7 MMBoe proved reserves, 37% PD 99% Permian Basin |
Oil-Focused, Pure-Play • Transitioning Wolfcamp B to development mode and preparing for full-scale exploitation • Pilot program evaluating additional Wolfcamp zones (A and C benches) • Adding 3 rd horizontal rig in January 2013 • Concentrated geographic footprint in the southern Midland Basin • 146,000 net, primarily contiguous acres, 100% operated • 64% of proved reserves are oil and NGLs Track Record of Growth at Low Costs Accelerating Horizontal Wolfcamp Development • Reserve and production CAGR since 2004 of 33% and 37%, respectively • Low-cost operator with best-in-class F&D and low lifting costs • $270 MM borrowing base • $222.6 MM estimated liquidity at 9/30/12 Strong Balance Sheet Multi-Year Drilling Inventory and Significant Resource Potential • 2,900+ identified drilling and recompletion locations • 500+ MMBoe of gross, unrisked resource potential • Rigorous pilot program has de-risked ~100,000 gross acres • Additional upside potential from tighter well spacing and multi-zone development Key Investor Highlights 4 STRENGTHS HIGHLIGHTS Note: See liquidity calculation in appendix. |
Track Record of Reserve and Production Growth • MY’12 reserves up 25% YoY and 9% over YE’11 Oil reserves up 30% to 23.5 MMbbls • Wolfcamp Shale key contributor to reserve growth 5 RESERVE GROWTH PRODUCTION GROWTH • 2011 production increased 50% YoY • Targeting 28% production growth in 2012 • Strong liquids production growth 2012E production 65% liquids 0 10 20 30 40 50 60 70 80 90 2004 2005 2006 2007 2008 2009 2010 2011 MY'12 Natural Gas (MMBoe) Oil & NGLs (MMbbls) 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 2004 2005 2006 2007 2008 2009 2010 2011 MY'12 Natural Gas (MBoe/d) Oil & NGLs (Mbbls/d) 500+ MMBoe gross, unrisked resource potential |
Low-Cost Operator 6 3-YR AVERAGE F&D COSTS ($/BOE) 2Q’12 LIFTING COSTS ($/BOE) Notes: Oil weighted peers include BRY, CXO, KOG, LPI, NOG, OAS. Data based on SEC filings and J.S. Herold data. 3-YR F&D costs represent drill-bit F&D costs (drill-bit F&D costs defined as Exploration and Development Costs divided by Reserve Extensions & Discoveries and Revisions less Production). See F&D costs reconciliation in appendix. Lifting costs defined as lease operating expense plus taxes other than income and gathering and transportation expense. |
Extensive Inventory of Future Drilling Locations 7 POTENTIAL DRILLING LOCATIONS Gross Resource Potential (MMBoe): 225 200+ 17+ 85 500+ 500+ MMBoe Total Gross Resource Potential |
AREX Wolfcamp Play Favorably Located in the S. Midland Basin 8 Wolfcamp / Wolffork Oil Shale Resource Play |
AREX Wolfcamp Oil Shale Resource Play 9 ACTIVE PARTICIPANTS IN THE PLAY Note: Number of Horizontal Wolfcamp rigs per PXD July 2012 investor presentation. Average 24-hr. IP rate and average lateral well length based on public disclosure from AREX, EOG, PXD. Large, primarily contiguous acreage position Liquids-rich, multiple pay zones 166,000 gross (146,000 net) acres Low acreage cost ~$500 per acre 500+ MMBoe gross, unrisked resource potential 2,900+ drilling and recompletion opportunities Early-stage play development Transitioning Wolfcamp B to development mode Testing Wolfcamp A and C Testing tighter well spacing Preparing field for large-scale development Broad industry participation de-risking play 41 Horizontal Wolfcamp rigs as of July 2012 Average 24-hr. IP rate of 807 Boe/d in 2Q’12 Average lateral well length of ~7,100 ft. |
10 Wolfcamp Oil Shale Play – Widespread, Thick, Consistent & Repeatable |
Horizontal Wolfcamp Targets 11 SYSTEM STRATIGRAPHIC UNIT Permian Clearfork/Spraberry Dean Wolfcamp Pennsylvanian Canyon Strawn Mississippian Devonian Silurian Ordovician Ellenburger WOLFCAMP A WOLFCAMP B WOLFCAMP C WOLFCAMP D Pilot Transitioning to Development Pilot – Recent Results Encouraging Under Evaluation POTENTIAL HORIZONTAL WOLFCAMP TARGETS |
12 AREX DVN PXD Highmount EP EOG Average ~82% Oil 59 wells from AREX, DVN, EOG, EP, Highmount and PXD Wolfcamp Horizontal Wells - 82% of IP is Oil Source: Publicly available regulatory filings, company presentations. |
Wolfcamp Horizontal Wells - 95% of IP is Liquids 13 AREX DVN PXD Highmount EP EOG Average ~95% Liquids 59 wells from AREX, DVN, EOG, EP, Highmount and PXD Source: Publicly available regulatory filings, company presentations. |
AREX Recent Well Results 14 IP MIX – LAST 10 HZ B WELLS 24 HR.- IP – LAST 10 HZ B WELLS HZ WOLFCAMP WELL RESULTS Boe/d Average: 918 Boe/d Average: 82% oil 72% 89% 87% 87% 92% 92% 65% 76% 76% 85% 0% 20% 40% 60% 80% 100% Oil NGLs Gas 14% 6% 7% 7% 4% 5% 19% 13% 13% 8% 14% 5% 6% 6% 4% 3% 16% 11% 11% 7% 811 1,044 1,310 1,136 687 892 676 634 1,111 875 0 200 400 600 800 1,000 1,200 1,400 Note: IP’s based on 24-hr. rates. We also recently completed three HZ B wells with an average IP of 500 Boe/d, made up of 62% oil and 83% total liquids. The average lateral length of the three HZ wells was 6,360 feet, including one well that was a 3,078-feet lateral. As part of ongoing cost cutting efforts, we reduced the amount of certain chemicals used in completing these wells. We believe that the change in the chemical composition of the frac fluid negatively affected the IP of these wells, and, accordingly, the results from these three HZ wells are not included in the above tables. Completion date Well name IP (Boe/d) Oil (Bbl/d) NGL (Bbl/d) Gas (Mcfe/d) IP % Liquids No. of stages B Bench: May 2012 University 45 A #703H 875 743 73 354 93% 29 Mar 2012 University 45 F #2304H 1,111 840 150 729 89% 28 Mar 2012 University 45 F #2303H 634 481 84 412 89% 30 Feb 2012 University 45 C #805H 676 441 130 632 84% 28 Feb 2012 University 45 C #804H 892 823 38 185 97% 35 Dec 2011 University 45 E #1101H 687 632 30 147 96% 35 Dec 2011 University 45 F #2302H 1,136 986 83 404 94% 28 Dec 2011 University 45 F #2301H 1,310 1,136 96 467 94% 34 Sep 2011 University 45 C #803H 1,044 931 57 335 95% 23 Sep 2011 University 45 B #2401H 811 582 116 677 86% 23 Sep 2011 University 45 D #902H 798 611 95 552 88% 23 Jun 2011 University 45 A #701H 694 613 41 237 94% 21 May 2011 CT G #701H 328 168 81 473 76% 23 Apr 2011 University 42-21 #1H 316 132 93 543 71% 21 Mar 2011 CT M #901H 171 51 61 355 65% 15 A Bench: Jun 2012 Pangea West #6601H 461 388 40 196 93% 29 Jun 2012 Pangea West #6602H 494 391 57 278 91% 28 C Bench: Nov 2011 University 42 B #1001H 541 324 120 584 82% 28 |
AREX Wolfcamp Play – Activity Map 15 Pangea West North & Central Pangea South Pangea • 18,000 gross acres • 2 HZ pilot wells with encouraging results Schleicher Crockett Irion Reagan • Interpreting newly acquired 3D seismic • Targeting HZ pilot well in Q4’12 • 59,000 gross acres • Continuing completion design improvement • 89,000 gross acres • Continuing HZ and V development • Continuing refining completion designs Sutton Legend Vertical Producer HZ Producer HZ – Waiting on Completion HZ – Drilling HZ – Permit Note: Acreage as of 6/30/2012. • 3D Seismic acquisition underway • Targeting HZ pilot well in Q4’12 |
Horizontal Wolfcamp Economics 16 Play Type Horizontal Wolfcamp Avg. EUR 450 MBoe Targeted Well Cost $5.5 MM Potential Locations 500 Gross Resource Potential 225 MMBoe BTAX IRR SENSITIVITIES • 2 HZ rigs running in Pangea / Pangea West • Improving IPs and liquids ratio driving higher returns • Recent well results range from 634 BOEPD to 1,310 BOEPD, made up of 84% to 97% liquids • 875 BOEPD initial IP for Univ. 45 A 703H, made up of 85% oil and 93% total liquids • 612 BOEPD and 539 BOEPD average 30-day and 60-day rates, respectively, for Univ. 45 A 703H Notes: IP’s based on 24-hr. rates. Potential locations are based on 1,000-feet spacing between each horizontal well. Economics assume NYMEX gas strip and NGL price based on 40% of WTI oil price. • Horizontal drilling improves recoveries and returns • Multiple, stacked horizontal targets • 7,000’+ lateral length • ~80% of EUR made up of oil and NGLs • 2 HZ rigs running in Project Pangea / Pangea West • Adding 3 HZ rig in January 2013 0 10 40 50 60 70 80 350 400 450 500 550 Well EUR (MBoe) $100 / bbl $90 / bbl $80 / bbl $70 / bbl 20 30 rd |
Horizontal Wolfcamp Type Curve 17 Month 100 1,000 10,000 100,000 6 12 18 24 30 36 42 48 54 60 0 Oil (barrels per month) NGL (barrels per month) Shrunk Gas (boe per month) Oil 45-701H NGL 45-701H Shrunk Gas 45-701H Total (boe per month) Total 45-701H 450,000 Boe Type Curve Production data (9 months) University 45-701H U 45-701H IP 694 Boe/d Type Curve IP 589 Boe/d |
Clearfork & Wolfcamp (“Wolffork”) Economics 18 BTAX IRR SENSITIVITIES Notes: Vertical Wolffork potential locations based on 20-acre spacing. Vertical Wolffork recompletion potential locations based on 20 to 40-acre spacing. Economics assume NYMEX gas strip and NGL price based on 40% of WTI oil price. Play Type Vertical Wolffork Recompletion Avg. EUR 93 MBoe Targeted Well Cost $0.75 MM Potential Locations 190 Gross Resource Potential 17+ MMBoe BTAX IRR SENSITIVITIES 0 10 20 30 40 100 105 110 115 120 Well EUR (MBoe) $100 / bbl $90 / bbl $80 / bbl $70 / bbl 0 10 20 30 40 50 60 70 80 76 86 96 106 Well EUR (MBoe) $100 / bbl $90 / bbl $80 / bbl $70 / bbl Play Type Vertical Wolffork Avg. EUR 110 MBoe Targeted Well Cost $1.2 MM Potential Locations 1,825 Gross Resource Potential 200+ MMBoe |
AREX Drilling Targets & Resource Potential 19 PLAY TYPE Horizontal Wolfcamp Vertical Wolffork Vertical Wolffork Recompletion Vertical Canyon Wolffork EUR (MBoe) 450 110 93 193 Targeted well cost ($MM) $5.5 $1.2 $0.75 $1.5 Potential locations 500 1,825 190 440 GROSS RESOURCE POTENTIAL (MMBoe) 225 200+ 17+ 85 Target Wolfcamp Clearfork, Wolfcamp Clearfork, Wolfcamp Canyon, Clearfork, Wolfcamp Drilling depth (ft.) 7,000+ (lateral length) < 7,500 < 7,500 < 8,500 500+ MMBoe Total Gross Resource Potential Notes: Potential locations based on 1,000-feet spacing between each horizontal well for Horizontal Wolfcamp, 20-acre spacing for Vertical Wolffork, 20 to 40- acre spacing for Vertical Wolffork Recompletion and 40-acre spacing for Vertical Canyon Wolffork. |
Infrastructure & Equipment Projects 20 • Safely and securely transport water across Project Pangea and Pangea West and reduce truck traffic • Reduce time and money spent on water hauling and disposal • Replace rental equipment and contractors with Company-owned and operated equipment and personnel • Reduce money spent on flowback operations • Facilitate large-scale field development • Reduce fresh water use • Reduce water costs • Efficiently transport crude oil to market and reduce inventory • Reduce oil differential Purchasing and installing water transfer equipment Drilling and/or converting SWD wells Purchasing and installing flowback equipment Securing water supply Testing non-potable water and recycling flowback water Installing crude takeaway lines Purchased oil hauling trucks PROJECTS BENEFITS Infrastructure and equipment projects are key to large-scale field development and to reducing D&C costs and monthly LOE |
2012 & 2013 Capital Programs 21 Infrastructure & Equipment Vertical Wolffork & Recompletions Horizontal Wolfcamp Acreage • Horizontal Wolfcamp 2 horizontal rigs Beginning development program of B zone Testing A & C zones • Vertical Clearfork & Wolfcamp 1 vertical rig and recompletion program 2012 PROGRAM OVERVIEW 2012 Capital Program $260 MM • Horizontal Wolfcamp 3 horizontal rigs to drill 35 to 40 wells • Vertical Clearfork & Wolfcamp 1 vertical rig to drill 12 wells Recompletion program 2013 PROGRAM OVERVIEW Vertical Wolffork & Recompletions Horizontal Wolfcamp Acreage, Infrastructure & Equipment 2013 Capital Program $260 MM 29% 14% 2% 55% 2% 10% 88% |
Creating Value Through Growth 22 • Concentrated geographic footprint in the Southern Midland Basin • Strong growth track record at competitive costs • Detailed technical evaluation led to discovery of significant growth potential in the Wolfcamp / Wolffork oil shale resource play • Rigorous pilot program de-risked ~100,000 gross acres • Capital discipline for Wolfcamp / Wolffork program acceleration |
Financial Framework NON-GAAP RECONCILIATIONS |
2012 Operating and Financial Guidance 24 2012 GUIDANCE 2012 Guidance Production Total (MBoe) 2,900 - 3,100 Percent Oil & NGLs 65% Operating costs and expenses ($/per Boe) Lease operating $ 5.50 – 6.50 Severance and production taxes $ 2.50 – 4.00 Exploration $ 4.00 – 5.00 General and administrative $ 7.00 – 8.00 Depletion, depreciation and amortization $ 15.00 – 18.00 Capital expenditures ($MM) Approximately $260 |
Hedge Position 25 CURRENT HEDGE POSITION Commodity and Time Period Type Volume Price Crude Oil 2012 Collar 700 Bbls/d $85.00/Bbl - $97.50/Bbl 2012 Collar 500 Bbls/d $90.00/Bbl - $106.10/Bbl September 2012 – December 2012 Collar 350 Bbls/d $90.00/Bbl - $102.30/Bbl 2013 Collar 650 Bbls/d $90.00/Bbl - $105.80/Bbl 2013 Collar 450 Bbls/d $90.00/Bbl - $101.45/Bbl 2014 Collar 550 Bbls/d $90.00/Bbl - $105.50/Bbl Natural Gas Liquids Natural Gasoline – February 2012 – December 2012 Swap 225 Bbls/d $95.55/Bbl Normal Butane – March 2012 – December 2012 Swap 225 Bbls/d $73.92/Bbl Natural Gas 2012 Call 230,000 MMBtu/month $6.00/MMBtu July 2012 – December 2012 Swap 360,000 MMBtu/month $2.70/MMBtu 2013 Swap 200,000 MMBtu/month $3.54/MMBtu |
Financial Strength 26 Liquidity (preliminary and unaudited) 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. Liquidity has limitations, and 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. Liquidity 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 estimated liquidity at September 30, 2012. Estimated liquidity includes net proceeds from our follow-on equity offering of 5.0 million shares at $30.50 per share. (in thousands) Liquidity at September 30, 2012 Borrowing base $ 270,000 Cash and cash equivalents 500 Long-term debt (47,600) Unused letters of credit (350) Liquidity $ 222,550 |
F&D Costs Reconciliation (unaudited) 27 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 Boe 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 SEC filings and posted on our website. 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 tables reflect the reconciliation of our estimated finding and development costs to the information required by paragraphs 11 and 21 of ASC 932-235. 2011 Reserve summary (MBoe) Balance – 12/31/2010 50,715 Extensions & discoveries 25,548 Purchases 10,498 Revisions (7,448) Production (2,338) Balance – 12/31/2011 76,975 Cost summary ($M) Acquisitions $ 93,251 Exploration costs 9,991 Development costs 182,522 Total 285,764 Finding & development costs ($/Boe) All-in F&D costs $ 9.99 Drill-bit F&D cost $ 7.54 Reserve replacement ratio (%) Extensions & discoveries (MBoe) 25,548 2011 Production (MBoe) (2,338) Reserve replacement 1,093% 3-Year reserve summary (MBoe) Balance – 12/31/2008 35,178 Extensions & discoveries 34,386 Purchases 12,456 Revisions 318 Production (5,363) Balance – 12/31/2010 76,975 Finding & development costs ($/Boe) 3-year All-in F&D costs $ 10.15 3-year Drill-bit F&D cost $ 8.20 Reserve replacement ratio (%) Extensions & discoveries (MBoe) 34,386 3-year Production (MBoe) (5,363) Reserve replacement 641% Cost summary ($M) Acquisitions $ 124,584 Exploration costs 14,348 Development costs 267,559 Total $ 406,491 |
Contact Information MEGAN P. HAYS Manager, Investor Relations & Corporate Communications 817.989.9000 x 2108 mhays@approachresources.com www.approachresources.com |