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AREX 2016 Wells Fargo West Coast Energy Presentation

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The document discusses AREX's operations in the Permian Basin, including its 167 million barrels of oil equivalent proved reserves, low cost structure, extensive drilling inventory, and significant resource potential from the Wolfcamp shale play. AREX has implemented enhanced completion designs that outperform type curves and reduced its lease operating expenses through the use of a centralized water recycling facility that lowers drilling and completion costs by reusing flowback and produced water.

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Wells Fargo West Coast Energy Conference JUNE 21, 2016
Forward-looking statements Wells Fargo West Coast Energy Conference – June 2016 2 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 Wolfcamp 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, identified 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 drilling project, 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 limited production experience with this project, 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. Cautionary statements regarding oil & gas quantities
AREX – positioned for a low commodity price environment AREX OVERVIEW ASSET OVERVIEW Enterprise value $619MM High-quality reserve base 167 MMBoe proved reserves 63% Liquids, 33% oil Permian core operating area with extensive inventory of low-risk, low-cost drilling locations 139,000 gross (126,000 net) acres ~1+ BnBoe gross, unrisked resource potential ~1,800 Identified HZ drilling locations targeting Wolfcamp A/B/C 2016 Capital program focused on aligning capex with cash flow Adequate operating cash flow to fund 2016 capital plan Stable leasehold that is largely HBP provides for flexible budget Improving commodity prices would allow us to seamlessly increase capital budget from ~$20 MM to ~$80 MM Note: Proved reserves as of 12/31/2015 and acreage as of 3/31/2016. 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 $2.99 per share on 4/27/2016, plus net debt as of 3/31/2016. 3Wells Fargo West Coast Energy Conference – June 2016
Strong track record of reserve and production growth 4 RESERVE GROWTH 0 20 40 60 80 100 120 140 160 180 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Gas (MMBoe) Oil & NGLs (MMBbls) • YE15 reserves up 14% YoY • Replaced 603% of produced reserves at a drill- bit F&D cost (non-GAAP) of $4.32/Boe1 • 154.6 MMBoe proved reserves booked to HZ Wolfcamp play MMBoe PRODUCTION GROWTH 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Natural Gas (MBoe/d) Oil & NGLs (Mbbls/d) • 2015 Production increased 10% YoY to a record 15.2 MBoe/d • Anticipating production decline in 2016 with significantly reduced capital budget MBoe/d 1. Drill-bit 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. See “F&D costs (unaudited)” slide for our calculation of F&D cost. Wells Fargo West Coast Energy Conference – June 2016
Heightened return on capital employed through decline management 5Wells Fargo West Coast Energy Conference – June 2016 AREX Gross Production AREX Net Production
Enhanced completion design drives outperformance 6 Note: Production data normalized for operational downtimeNote: Production data normalized for operational downtime 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 1 31 61 91 121 151 181 211 241 271 301 331 361 391 2015 Wolfcamp B&C bench completions Average completed lateral length = 6886' CumulativeProduction(Boe) • Reduced stage spacing (< 200’) • Increase percentage of 100 mesh sand • Use of Recycled Produced Water Wells Fargo West Coast Energy Conference – June 2016
Large resource potential with significant running room 7Wells Fargo West Coast Energy Conference – June 2016 PDP: 164 wells 9% PDNP & PUD: 251 locations 14% Probable, Possible & Resource: 1,389 locations 77% A Bench: 589 locations 36% B Bench: 501 locations 31% C Bench: 549 locations 33% AREX Horizontal Wells / Locations AREX Undrilled Locations Total identified undrilled locations: 1,639
PDP PUD PDP PUD PROB/POSS/RES Potential ~10,000’ laterals PROB/POSS/RES Potential ~10,000’ laterals PDNP 548 PDP 16 PUD 41 PROB / POSS / RES 2015 Year End A Bench (TOTAL) PDNP 1 AREX Wolfcamp A Bench wells and locations Production Corridor Production Corridor Production Corridor Production Corridor Production Corridor Pangea West Project Pangea 8Wells Fargo West Coast Energy Conference – June 2016
PDP PUD PROB/POSS/RES PUD PROB/POSS/RES Potential ~10,000’ laterals Potential ~10,000’ laterals Production Corridor Production Corridor Production Corridor Production Corridor Production Corridor PDP 392 PDP 105 PUD 109 PROB / POSS / RES 2015 Year End B Bench (TOTAL) AREX Wolfcamp B Bench wells and locations Pangea West Project Pangea 9Wells Fargo West Coast Energy Conference – June 2016
PDP PROB/POSS/RES Potential ~10,000’ laterals PDP PUD PROB/POSS/RES Potential ~10,000’ laterals PUD 449 PDP 43 PUD 100 PROB / POSS / RES 2015 Year End C Bench (TOTAL) AREX Wolfcamp C Bench wells and locations Production Corridor Production Corridor Production Corridor Production Corridor Production Corridor Pangea West Project Pangea 10Wells Fargo West Coast Energy Conference – June 2016
11 $7.36 $6.18 $5.87 $6.65 $5.55 $4.97 $5.04 $5.44 $5.45 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 AREX LOE Historical Track Record ($/Boe) 2015 Permian Peer LOE ($/Boe) AREX D&C Historical Track Record ($ MM) Current Permian Peer D&C Cost ($ MM) $13.23 $9.51 $8.84 $7.83 $7.71 $7.46 $7.34 $6.92 $6.63 $6.39 $5.24 $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 AREX $8.6 $7.0 $5.8 $5.5 $4.5 $3.7 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 2011 2012 2013 2014 2015 Current AFE $7.8 $6.8 $6.6 $6.5 $5.8 $5.5 $5.5 $5.3 $5.2 $5.0 $3.7 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 AREX Source: Latest available company presentations and public filings. Peers include CPE, CWEI, CXO, EGN, FANG, LPI, MTDR, PE, PXD, and RSPP. Lowest cost structure in the Permian Basin Wells Fargo West Coast Energy Conference – June 2016
Established infrastructure in place is critical to low cost structure 12 Over 500 miles of pipelines in place • More than 100 MMcfg/d gathering and gas lifting capacity • Expandable up to 500 MMcfg/d One Centralized Super Water Recycle Center • 2.2 MM Bbls flowback and produced water recycled during 1st six months of operation • Reduced D&C cost by $450,000 per well • Reduced LOE by over $4MM • Reduced current SWD cost by ~$10,000/d Wells Fargo West Coast Energy Conference – June 2016
Significant cost savings from using recycled water for fracing 13 Flowback / Producing Well $2 per barrel Free Wellpad Via existing water gathering lines Cost Savings $400,000 to $600,000 per well Via existing water transportation lines $0.25 per barrel $0.25 per barrel $1.50 per barrel Free Water Recycling Center Cost for recycled water $2 - $3 per barrel Cost saving for using recycled water Wells Fargo West Coast Energy Conference – June 2016
AREX flowback and produced water recycle facility 14 32,000 BBL Dirty Water TankSkim Oil Sales Flowback & Produced Water Offloading Terminal & Separation Facility Flowback & Produced Water Supply 90 BPM Pump StationWater Treatment & Filtration Facility 63,000 BBL Treated Water Tank 44,000 BBL Treated Water Tank 8”Flowback&ProducedSaltwaterLine 8”LowChlorideTreatedFracWaterSupplyLine 20”TreatedFlowback&ProducedFracWaterSupplyLine 32,000 BBL Treated Water Tank N 63,000 BBL Treated Water Tank 63,000 BBL Treated Water Tank 32,000 BBL Treated Water Tank 32,000 BBL Treated Water Tank Centralized SWD Hauling Station 12” Poly 4” Connections Flowback / Produced Water Separator Dirty Water Tank Chemical Treatment & Centrifuge Treated Water Tank Pump Station & Water Supply Line 329,000 Bbls. of Produced Water Storage Capacity (above ground) Wells Fargo West Coast Energy Conference – June 2016
AREX flowback and produced water recycle facility 15 • Best practice for water conservation and improving water use efficiency • Reduces demand on fresh water sources • Reduces road damage & air pollution • Reduces D&C cost • Reduces SWD cost • Designed one of the highest industry KPI for water treatment  Bacteria  Sulfates  Heavy metals  Fines Wells Fargo West Coast Energy Conference – June 2016
AREX water recycling facility successfully implemented 16 0 5,000 10,000 15,000 20,000 25,000 30,000 RecycledWater(Bbls/d) • Started up in March 2015, ramped up during April 2015 • Recycled up to 100% of AREX daily flowback/produced water volumes • More than 2.2 million barrels of produced water treated in the first 6 months • More than $7mm of cost saved or value created in the first 6 months of operation Wells Fargo West Coast Energy Conference – June 2016
17 CPF 5CPF 1 CPF 2 CPF 3 CPF 4 Low Pressure Gathering Line 0.75 miles CS 0.75 miles Dehy ~ 2000 ft ~500ft High Pressure Sale / Gas Lift line Wells CPF 10CPF 6 CPF 7 CPF 8 CPF 9 Low Pressure Gathering Line CS Dehy Well Pads Serviced by Centralized Compressor and Shared Gas Lift System – Efficient and Significant Cost Saving Cost ~ $4.3 M / Well / month for the 1st 30 months This configuration saves $7.6 M / well / month for the 1st 30 months Or $228M/well for the 1st 30 months
D&C Cost reductions have significantly improved profitability despite lower commodity prices 18 Note: HZ Wolfcamp economics assume $3.50/Mcf realized natural gas price and NGL price based on 40% of realized oil price. 0% 10% 20% 30% 40% 50% 60% 70% $30 $40 $50 $60 $70 $80 IRR(%) Realized Oil Price ($/Bbl) $3.5MM D&C $4.0MM D&C $4.5MM D&C Wells Fargo West Coast Energy Conference – June 2016
Wells Fargo West Coast Energy Conference – June 2016 Balance sheet detail 19 AREX Liquidity and Capitalization• Following the Spring 2016 redetermination, our lenders set the borrowing base and commitment amount at $325 MM, while agreeing to a number of amendments designed to provide additional flexibility • Interest coverage covenant of 1.25x (or 1.00x following the issuance of junior secured debt) through 12/31/17, moving to 1.5x through 12/31/18 and 2.0x thereafter • $150 MM permitted debt basket allows for issuance of new junior secured debt • 2016 capital budget targeted to match operating cash flow • Pro forma liquidity2 of $54 MM provides additional flexibility • LTM EBITDAX3 / LTM Interest of 3.9x and current ratio of 6.7x, well above minimum covenant requirements • No near-term debt maturities AREX Debt Maturity Schedule ($ MM) AREX Capitalization as of 3/31/2016 ($ MM) Cash $0.8 Credit Facility 269.9 7.0% Senior Notes due 2021 226.1 Total Long-Term Debt 1 $496.0 Shareholders’ Equity 595.8 Total Book Capitalization $1,091.8 AREX Pro Forma Liquidity2 Borrowing Base $325.0 Cash and Cash Equivalents 0.8 Borrowings under Credit Facility (272.0) Undrawn Letters of Credit (0.3) Liquidity $53.5 $272.0 $230.3 $0.0 $50.0 $100.0 $150.0 $200.0 $250.0 $300.0 $350.0 $400.0 2016 2017 2018 2019 2020 2021 7.0% Senior Notes 1. Long-term debt is net of debt issuance costs of $6.4 million as of March 31, 2016 Revolving Credit Facility 2. See “Liquidity (unaudited)” slide for pro forma reconciliation. 3. See “EBITDAX (unaudited)” slide for reconciliation to GAAP measure.
Key investment highlights 20 Prudent and proactive management team • Strategic leadership provides short term stability – long term viability • First public E&P company to fully suspend capital spending in August 2015 • Generated positive cash flow in 4Q15, used to reduce current liabilities by ~$17MM and total debt by ~$20MM Focus on Value Creation and Key Drivers that Create Repeatable Economic Results • Infrastructure • Capitalize on contiguous acreage position • Strategic investment that will provide economic benefit for decades • Optimized completions • Operational results drive value • Low Cost Driller in the Midland Basin - current AFEs now averaging $3.7MM, with potential for further reductions during 2016 • YE15 Drill bit F&D cost $4.32/Boe, down 52% from 2014 • 2015 Lease operating expense of $5.24/Boe remains lowest among Permian Basin peers • Recent wells achieving ~15% IRR at current NYMEX strip prices Continuing to prioritize liquidity and cash flow over growth in 2016 • Two wells completed and currently flowing back for 2Q16 after nine months of natural PDP production decline • Production estimated at 12.3 Mboe/d for 2Q16 with shallow decline • Well-hedged in 2016 and beginning to opportunistically add 2017 hedges • No near-term debt maturities, obtained meaningful covenant relief and additional flexibility following Spring 2016 redetermination Wells Fargo West Coast Energy Conference – June 2016
Appendix
Wells Fargo West Coast Energy Conference – June 2016 Current hedge position 22 • Based on the midpoint of current 2016 guidance, approximately 48% of forecasted oil production and 75% of forecasted natural gas production are hedged at weighted average prices of $50.56/Bbl and $2.61/MMBtu, respectively. Commodity & Period Contract Type Volume Contract Price Crude Oil April 2016 – December 2016 Swap 750 Bbls/d $62.52/Bbl April 2016 – June 2016 Swap 1,000 Bbls/d $40.00/Bbl April 2016 – June 2016 Swap 500 Bbls/d $40.25/Bbl April 2016 – September 2016 Swap 750 Bbls/d $43.00/Bbl Natural Gas April 2016 – December 2016 Swap 200,000 MMBtu/month $2.93/MMBtu April 2016 – March 2017 Swap 400,000 MMBtu/month $2.45/MMBtu April 2017 – December 2017 Collar 200,000 MMBtu/month $2.30/MMBtu - $2.60/MMBtu
Wells Fargo West Coast Energy Conference – June 2016 Production and expense guidance 23 2016 Guidance Production Oil (MBbls) 1,300 – 1,400 NGLs (MBbls) 1,440 – 1,540 Natural Gas (MMcf) 9,600 – 10,100 Total (MBoe) 4,340 – 4,625 Cash operating costs (per Boe) Lease operating $5.00 - $6.00 Production and ad valorem taxes 8.0% of oil & gas revenues Cash general and administrative $3.50 - $4.00 Non-cash operating costs (per Boe) Non-cash general and administrative $1.00 - $1.50 Exploration (non-cash) $0.50 - $1.00 Depletion, depreciation and amortization $18.00 - $20.00 Capital expenditures (in millions) ~$20
AREX Wolfcamp acreage is offset by large operators 24 Pangea West EOG HENRY ENERVEST EP ENERGY others APA PXD DVN AREX AREX AREX AREX APA APA DVN DVN ELEVATION PXD DVN APA APA APA EOG Pangea ENERVEST EOG / EAP EAP BROADOAK ENDEAVOR APA UPTON CROCKETT REAGAN IRION SCHLEICHER SUTTON EP ENERGY AREX AREX AREX AREX EOG Wells Fargo West Coast Energy Conference – June 2016
Wells Fargo West Coast Energy Conference – June 2016 EBITDAX (unaudited) 25 We define EBITDAX as net loss, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, net, and (6) income tax benefit. 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 loss 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. The following table provides a reconciliation of EBITDAX to net loss for the three months ended March 31, 2016 and 2015. (in thousands, except per-share amounts) Three Months Ended March 31, 2016 2015 Net loss $ (13,660) $ (7,708) Exploration 569 1,090 Depletion, depreciation and amortization 20,229 26,520 Share-based compensation 1,550 2,217 Unrealized loss on commodity derivatives 957 9,321 Interest expense, net 6,298 5,922 Income tax benefit (7,245) (3,996) EBITDAX $ 8,698 $ 33,366 EBITDAX per diluted share $ 0.21 $ 0.83
Cash operating expenses (unaudited) 26 We define cash operating expenses as operating expenses, excluding (1) exploration expense, (2) depletion, depreciation and amortization expense, and (3) share-based compensation expense. Cash operating expenses is not a measure of operating expenses as determined by GAAP. The amounts included in the calculation of cash operating expenses were computed in accordance with GAAP. Cash operating expenses is presented herein and reconciled to the GAAP measure of operating expenses. We use cash operating expenses as an indicator of the Company’s ability to manage its operating expenses and cash flows. 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. The following table provides a reconciliation of cash operating expenses to operating expenses for the three months ended March 31, 2016 and 2015. (in thousands, except per-Boe amounts) Three Months Ended March 31, 2016 2015 Operating expenses $ 34,869 $ 45,686 Exploration (569) (1,090) Depletion, depreciation and amortization (20,229) (26,520) Share-based compensation (1,550) (2,217) Cash operating expenses $ 12,521 $ 15,859 Cash operating expenses per Boe $ 10.74 $ 12.32 Wells Fargo West Coast Energy Conference – June 2016
Liquidity (unaudited) 27 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 March 31, 2016, and pro forma for the third amendment to our revolving credit facility at March 31, 2016. (in thousands) Liquidity at March 31, 2016 Pro forma Borrowing base $ 450,000 $ 325,000 Cash and cash equivalents 840 840 Revolving credit facility – outstanding borrowings (272,000) (272,000) Outstanding letters of credit (325) (325) Liquidity $ 178,515 $ 53,515 Wells Fargo West Coast Energy Conference – June 2016
Wells Fargo West Coast Energy Conference – June 2016 F&D costs (unaudited) 28 F&D Cost reconciliation Cost summary (in thousands) Property acquisition costs Unproved properties $ 653 Proved properties - Exploration costs 4,439 Development costs 146,237 Total costs incurred $ 151,329 Reserves summary (MBoe) Balance – 12/31/2014 146,248 Extensions & discoveries 34,895 Production (1) (5,787) Revisions to previous estimates (8,709) Balance – 12/31/2015 166,646 F&D cost ($/Boe) All-in F&D cost $ 5.78 Drill-bit F&D cost 4.32 Reserve replacement ratio Drill-bit 603% All-in finding and development (“F&D”) costs are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year by the sum of reserve extensions and discoveries, purchases of minerals in place and total revisions for the year. Drill-bit 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. We believe that providing F&D cost is useful to assist in 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 previous SEC filings and included in our annual report on Form 10-K filed with the SEC on March 4, 2016. 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 used by us 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 reconciles our estimated F&D costs for 2015 to the information required by paragraphs 11 and 21 of ASC 932-235. (1) Production includes 1,530 MMcf related to field fuel.
Wells Fargo West Coast Energy Conference – June 2016 PV-10 (unaudited) 29 The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $504 million at December 31, 2015, and was calculated based on the first-of-the-month, twelve-month average prices for oil, NGLs and gas, of $50.16 per Bbl of oil, $15.13 per Bbl of NGLs and $2.64 per MMBtu of natural gas, adjusted for basis differentials, grade and quality. PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. The following table reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP. (in millions) December 31, 2015 PV-10 $ 504 Less income taxes: Undiscounted future income taxes (307) 10% discount factor 263 Future discounted income taxes (44) Standardized measure of discounted future net cash flows $ 460
Contact information SUZANNE OGLE Vice President – Investor Relations & Corporate Communications 817.989.9000 ir@approachresources.com www.approachresources.com

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AREX 2016 Wells Fargo West Coast Energy Presentation

  • 1. Wells Fargo West Coast Energy Conference JUNE 21, 2016
  • 2. Forward-looking statements Wells Fargo West Coast Energy Conference – June 2016 2 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 Wolfcamp 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, identified 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 drilling project, 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 limited production experience with this project, 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. Cautionary statements regarding oil & gas quantities
  • 3. AREX – positioned for a low commodity price environment AREX OVERVIEW ASSET OVERVIEW Enterprise value $619MM High-quality reserve base 167 MMBoe proved reserves 63% Liquids, 33% oil Permian core operating area with extensive inventory of low-risk, low-cost drilling locations 139,000 gross (126,000 net) acres ~1+ BnBoe gross, unrisked resource potential ~1,800 Identified HZ drilling locations targeting Wolfcamp A/B/C 2016 Capital program focused on aligning capex with cash flow Adequate operating cash flow to fund 2016 capital plan Stable leasehold that is largely HBP provides for flexible budget Improving commodity prices would allow us to seamlessly increase capital budget from ~$20 MM to ~$80 MM Note: Proved reserves as of 12/31/2015 and acreage as of 3/31/2016. 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 $2.99 per share on 4/27/2016, plus net debt as of 3/31/2016. 3Wells Fargo West Coast Energy Conference – June 2016
  • 4. Strong track record of reserve and production growth 4 RESERVE GROWTH 0 20 40 60 80 100 120 140 160 180 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Gas (MMBoe) Oil & NGLs (MMBbls) • YE15 reserves up 14% YoY • Replaced 603% of produced reserves at a drill- bit F&D cost (non-GAAP) of $4.32/Boe1 • 154.6 MMBoe proved reserves booked to HZ Wolfcamp play MMBoe PRODUCTION GROWTH 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Natural Gas (MBoe/d) Oil & NGLs (Mbbls/d) • 2015 Production increased 10% YoY to a record 15.2 MBoe/d • Anticipating production decline in 2016 with significantly reduced capital budget MBoe/d 1. Drill-bit 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. See “F&D costs (unaudited)” slide for our calculation of F&D cost. Wells Fargo West Coast Energy Conference – June 2016
  • 5. Heightened return on capital employed through decline management 5Wells Fargo West Coast Energy Conference – June 2016 AREX Gross Production AREX Net Production
  • 6. Enhanced completion design drives outperformance 6 Note: Production data normalized for operational downtimeNote: Production data normalized for operational downtime 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 1 31 61 91 121 151 181 211 241 271 301 331 361 391 2015 Wolfcamp B&C bench completions Average completed lateral length = 6886' CumulativeProduction(Boe) • Reduced stage spacing (< 200’) • Increase percentage of 100 mesh sand • Use of Recycled Produced Water Wells Fargo West Coast Energy Conference – June 2016
  • 7. Large resource potential with significant running room 7Wells Fargo West Coast Energy Conference – June 2016 PDP: 164 wells 9% PDNP & PUD: 251 locations 14% Probable, Possible & Resource: 1,389 locations 77% A Bench: 589 locations 36% B Bench: 501 locations 31% C Bench: 549 locations 33% AREX Horizontal Wells / Locations AREX Undrilled Locations Total identified undrilled locations: 1,639
  • 8. PDP PUD PDP PUD PROB/POSS/RES Potential ~10,000’ laterals PROB/POSS/RES Potential ~10,000’ laterals PDNP 548 PDP 16 PUD 41 PROB / POSS / RES 2015 Year End A Bench (TOTAL) PDNP 1 AREX Wolfcamp A Bench wells and locations Production Corridor Production Corridor Production Corridor Production Corridor Production Corridor Pangea West Project Pangea 8Wells Fargo West Coast Energy Conference – June 2016
  • 9. PDP PUD PROB/POSS/RES PUD PROB/POSS/RES Potential ~10,000’ laterals Potential ~10,000’ laterals Production Corridor Production Corridor Production Corridor Production Corridor Production Corridor PDP 392 PDP 105 PUD 109 PROB / POSS / RES 2015 Year End B Bench (TOTAL) AREX Wolfcamp B Bench wells and locations Pangea West Project Pangea 9Wells Fargo West Coast Energy Conference – June 2016
  • 10. PDP PROB/POSS/RES Potential ~10,000’ laterals PDP PUD PROB/POSS/RES Potential ~10,000’ laterals PUD 449 PDP 43 PUD 100 PROB / POSS / RES 2015 Year End C Bench (TOTAL) AREX Wolfcamp C Bench wells and locations Production Corridor Production Corridor Production Corridor Production Corridor Production Corridor Pangea West Project Pangea 10Wells Fargo West Coast Energy Conference – June 2016
  • 11. 11 $7.36 $6.18 $5.87 $6.65 $5.55 $4.97 $5.04 $5.44 $5.45 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 AREX LOE Historical Track Record ($/Boe) 2015 Permian Peer LOE ($/Boe) AREX D&C Historical Track Record ($ MM) Current Permian Peer D&C Cost ($ MM) $13.23 $9.51 $8.84 $7.83 $7.71 $7.46 $7.34 $6.92 $6.63 $6.39 $5.24 $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 AREX $8.6 $7.0 $5.8 $5.5 $4.5 $3.7 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 2011 2012 2013 2014 2015 Current AFE $7.8 $6.8 $6.6 $6.5 $5.8 $5.5 $5.5 $5.3 $5.2 $5.0 $3.7 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 AREX Source: Latest available company presentations and public filings. Peers include CPE, CWEI, CXO, EGN, FANG, LPI, MTDR, PE, PXD, and RSPP. Lowest cost structure in the Permian Basin Wells Fargo West Coast Energy Conference – June 2016
  • 12. Established infrastructure in place is critical to low cost structure 12 Over 500 miles of pipelines in place • More than 100 MMcfg/d gathering and gas lifting capacity • Expandable up to 500 MMcfg/d One Centralized Super Water Recycle Center • 2.2 MM Bbls flowback and produced water recycled during 1st six months of operation • Reduced D&C cost by $450,000 per well • Reduced LOE by over $4MM • Reduced current SWD cost by ~$10,000/d Wells Fargo West Coast Energy Conference – June 2016
  • 13. Significant cost savings from using recycled water for fracing 13 Flowback / Producing Well $2 per barrel Free Wellpad Via existing water gathering lines Cost Savings $400,000 to $600,000 per well Via existing water transportation lines $0.25 per barrel $0.25 per barrel $1.50 per barrel Free Water Recycling Center Cost for recycled water $2 - $3 per barrel Cost saving for using recycled water Wells Fargo West Coast Energy Conference – June 2016
  • 14. AREX flowback and produced water recycle facility 14 32,000 BBL Dirty Water TankSkim Oil Sales Flowback & Produced Water Offloading Terminal & Separation Facility Flowback & Produced Water Supply 90 BPM Pump StationWater Treatment & Filtration Facility 63,000 BBL Treated Water Tank 44,000 BBL Treated Water Tank 8”Flowback&ProducedSaltwaterLine 8”LowChlorideTreatedFracWaterSupplyLine 20”TreatedFlowback&ProducedFracWaterSupplyLine 32,000 BBL Treated Water Tank N 63,000 BBL Treated Water Tank 63,000 BBL Treated Water Tank 32,000 BBL Treated Water Tank 32,000 BBL Treated Water Tank Centralized SWD Hauling Station 12” Poly 4” Connections Flowback / Produced Water Separator Dirty Water Tank Chemical Treatment & Centrifuge Treated Water Tank Pump Station & Water Supply Line 329,000 Bbls. of Produced Water Storage Capacity (above ground) Wells Fargo West Coast Energy Conference – June 2016
  • 15. AREX flowback and produced water recycle facility 15 • Best practice for water conservation and improving water use efficiency • Reduces demand on fresh water sources • Reduces road damage & air pollution • Reduces D&C cost • Reduces SWD cost • Designed one of the highest industry KPI for water treatment  Bacteria  Sulfates  Heavy metals  Fines Wells Fargo West Coast Energy Conference – June 2016
  • 16. AREX water recycling facility successfully implemented 16 0 5,000 10,000 15,000 20,000 25,000 30,000 RecycledWater(Bbls/d) • Started up in March 2015, ramped up during April 2015 • Recycled up to 100% of AREX daily flowback/produced water volumes • More than 2.2 million barrels of produced water treated in the first 6 months • More than $7mm of cost saved or value created in the first 6 months of operation Wells Fargo West Coast Energy Conference – June 2016
  • 17. 17 CPF 5CPF 1 CPF 2 CPF 3 CPF 4 Low Pressure Gathering Line 0.75 miles CS 0.75 miles Dehy ~ 2000 ft ~500ft High Pressure Sale / Gas Lift line Wells CPF 10CPF 6 CPF 7 CPF 8 CPF 9 Low Pressure Gathering Line CS Dehy Well Pads Serviced by Centralized Compressor and Shared Gas Lift System – Efficient and Significant Cost Saving Cost ~ $4.3 M / Well / month for the 1st 30 months This configuration saves $7.6 M / well / month for the 1st 30 months Or $228M/well for the 1st 30 months
  • 18. D&C Cost reductions have significantly improved profitability despite lower commodity prices 18 Note: HZ Wolfcamp economics assume $3.50/Mcf realized natural gas price and NGL price based on 40% of realized oil price. 0% 10% 20% 30% 40% 50% 60% 70% $30 $40 $50 $60 $70 $80 IRR(%) Realized Oil Price ($/Bbl) $3.5MM D&C $4.0MM D&C $4.5MM D&C Wells Fargo West Coast Energy Conference – June 2016
  • 19. Wells Fargo West Coast Energy Conference – June 2016 Balance sheet detail 19 AREX Liquidity and Capitalization• Following the Spring 2016 redetermination, our lenders set the borrowing base and commitment amount at $325 MM, while agreeing to a number of amendments designed to provide additional flexibility • Interest coverage covenant of 1.25x (or 1.00x following the issuance of junior secured debt) through 12/31/17, moving to 1.5x through 12/31/18 and 2.0x thereafter • $150 MM permitted debt basket allows for issuance of new junior secured debt • 2016 capital budget targeted to match operating cash flow • Pro forma liquidity2 of $54 MM provides additional flexibility • LTM EBITDAX3 / LTM Interest of 3.9x and current ratio of 6.7x, well above minimum covenant requirements • No near-term debt maturities AREX Debt Maturity Schedule ($ MM) AREX Capitalization as of 3/31/2016 ($ MM) Cash $0.8 Credit Facility 269.9 7.0% Senior Notes due 2021 226.1 Total Long-Term Debt 1 $496.0 Shareholders’ Equity 595.8 Total Book Capitalization $1,091.8 AREX Pro Forma Liquidity2 Borrowing Base $325.0 Cash and Cash Equivalents 0.8 Borrowings under Credit Facility (272.0) Undrawn Letters of Credit (0.3) Liquidity $53.5 $272.0 $230.3 $0.0 $50.0 $100.0 $150.0 $200.0 $250.0 $300.0 $350.0 $400.0 2016 2017 2018 2019 2020 2021 7.0% Senior Notes 1. Long-term debt is net of debt issuance costs of $6.4 million as of March 31, 2016 Revolving Credit Facility 2. See “Liquidity (unaudited)” slide for pro forma reconciliation. 3. See “EBITDAX (unaudited)” slide for reconciliation to GAAP measure.
  • 20. Key investment highlights 20 Prudent and proactive management team • Strategic leadership provides short term stability – long term viability • First public E&P company to fully suspend capital spending in August 2015 • Generated positive cash flow in 4Q15, used to reduce current liabilities by ~$17MM and total debt by ~$20MM Focus on Value Creation and Key Drivers that Create Repeatable Economic Results • Infrastructure • Capitalize on contiguous acreage position • Strategic investment that will provide economic benefit for decades • Optimized completions • Operational results drive value • Low Cost Driller in the Midland Basin - current AFEs now averaging $3.7MM, with potential for further reductions during 2016 • YE15 Drill bit F&D cost $4.32/Boe, down 52% from 2014 • 2015 Lease operating expense of $5.24/Boe remains lowest among Permian Basin peers • Recent wells achieving ~15% IRR at current NYMEX strip prices Continuing to prioritize liquidity and cash flow over growth in 2016 • Two wells completed and currently flowing back for 2Q16 after nine months of natural PDP production decline • Production estimated at 12.3 Mboe/d for 2Q16 with shallow decline • Well-hedged in 2016 and beginning to opportunistically add 2017 hedges • No near-term debt maturities, obtained meaningful covenant relief and additional flexibility following Spring 2016 redetermination Wells Fargo West Coast Energy Conference – June 2016
  • 22. Wells Fargo West Coast Energy Conference – June 2016 Current hedge position 22 • Based on the midpoint of current 2016 guidance, approximately 48% of forecasted oil production and 75% of forecasted natural gas production are hedged at weighted average prices of $50.56/Bbl and $2.61/MMBtu, respectively. Commodity & Period Contract Type Volume Contract Price Crude Oil April 2016 – December 2016 Swap 750 Bbls/d $62.52/Bbl April 2016 – June 2016 Swap 1,000 Bbls/d $40.00/Bbl April 2016 – June 2016 Swap 500 Bbls/d $40.25/Bbl April 2016 – September 2016 Swap 750 Bbls/d $43.00/Bbl Natural Gas April 2016 – December 2016 Swap 200,000 MMBtu/month $2.93/MMBtu April 2016 – March 2017 Swap 400,000 MMBtu/month $2.45/MMBtu April 2017 – December 2017 Collar 200,000 MMBtu/month $2.30/MMBtu - $2.60/MMBtu
  • 23. Wells Fargo West Coast Energy Conference – June 2016 Production and expense guidance 23 2016 Guidance Production Oil (MBbls) 1,300 – 1,400 NGLs (MBbls) 1,440 – 1,540 Natural Gas (MMcf) 9,600 – 10,100 Total (MBoe) 4,340 – 4,625 Cash operating costs (per Boe) Lease operating $5.00 - $6.00 Production and ad valorem taxes 8.0% of oil & gas revenues Cash general and administrative $3.50 - $4.00 Non-cash operating costs (per Boe) Non-cash general and administrative $1.00 - $1.50 Exploration (non-cash) $0.50 - $1.00 Depletion, depreciation and amortization $18.00 - $20.00 Capital expenditures (in millions) ~$20
  • 24. AREX Wolfcamp acreage is offset by large operators 24 Pangea West EOG HENRY ENERVEST EP ENERGY others APA PXD DVN AREX AREX AREX AREX APA APA DVN DVN ELEVATION PXD DVN APA APA APA EOG Pangea ENERVEST EOG / EAP EAP BROADOAK ENDEAVOR APA UPTON CROCKETT REAGAN IRION SCHLEICHER SUTTON EP ENERGY AREX AREX AREX AREX EOG Wells Fargo West Coast Energy Conference – June 2016
  • 25. Wells Fargo West Coast Energy Conference – June 2016 EBITDAX (unaudited) 25 We define EBITDAX as net loss, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, net, and (6) income tax benefit. 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 loss 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. The following table provides a reconciliation of EBITDAX to net loss for the three months ended March 31, 2016 and 2015. (in thousands, except per-share amounts) Three Months Ended March 31, 2016 2015 Net loss $ (13,660) $ (7,708) Exploration 569 1,090 Depletion, depreciation and amortization 20,229 26,520 Share-based compensation 1,550 2,217 Unrealized loss on commodity derivatives 957 9,321 Interest expense, net 6,298 5,922 Income tax benefit (7,245) (3,996) EBITDAX $ 8,698 $ 33,366 EBITDAX per diluted share $ 0.21 $ 0.83
  • 26. Cash operating expenses (unaudited) 26 We define cash operating expenses as operating expenses, excluding (1) exploration expense, (2) depletion, depreciation and amortization expense, and (3) share-based compensation expense. Cash operating expenses is not a measure of operating expenses as determined by GAAP. The amounts included in the calculation of cash operating expenses were computed in accordance with GAAP. Cash operating expenses is presented herein and reconciled to the GAAP measure of operating expenses. We use cash operating expenses as an indicator of the Company’s ability to manage its operating expenses and cash flows. 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. The following table provides a reconciliation of cash operating expenses to operating expenses for the three months ended March 31, 2016 and 2015. (in thousands, except per-Boe amounts) Three Months Ended March 31, 2016 2015 Operating expenses $ 34,869 $ 45,686 Exploration (569) (1,090) Depletion, depreciation and amortization (20,229) (26,520) Share-based compensation (1,550) (2,217) Cash operating expenses $ 12,521 $ 15,859 Cash operating expenses per Boe $ 10.74 $ 12.32 Wells Fargo West Coast Energy Conference – June 2016
  • 27. Liquidity (unaudited) 27 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 March 31, 2016, and pro forma for the third amendment to our revolving credit facility at March 31, 2016. (in thousands) Liquidity at March 31, 2016 Pro forma Borrowing base $ 450,000 $ 325,000 Cash and cash equivalents 840 840 Revolving credit facility – outstanding borrowings (272,000) (272,000) Outstanding letters of credit (325) (325) Liquidity $ 178,515 $ 53,515 Wells Fargo West Coast Energy Conference – June 2016
  • 28. Wells Fargo West Coast Energy Conference – June 2016 F&D costs (unaudited) 28 F&D Cost reconciliation Cost summary (in thousands) Property acquisition costs Unproved properties $ 653 Proved properties - Exploration costs 4,439 Development costs 146,237 Total costs incurred $ 151,329 Reserves summary (MBoe) Balance – 12/31/2014 146,248 Extensions & discoveries 34,895 Production (1) (5,787) Revisions to previous estimates (8,709) Balance – 12/31/2015 166,646 F&D cost ($/Boe) All-in F&D cost $ 5.78 Drill-bit F&D cost 4.32 Reserve replacement ratio Drill-bit 603% All-in finding and development (“F&D”) costs are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year by the sum of reserve extensions and discoveries, purchases of minerals in place and total revisions for the year. Drill-bit 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. We believe that providing F&D cost is useful to assist in 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 previous SEC filings and included in our annual report on Form 10-K filed with the SEC on March 4, 2016. 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 used by us 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 reconciles our estimated F&D costs for 2015 to the information required by paragraphs 11 and 21 of ASC 932-235. (1) Production includes 1,530 MMcf related to field fuel.
  • 29. Wells Fargo West Coast Energy Conference – June 2016 PV-10 (unaudited) 29 The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $504 million at December 31, 2015, and was calculated based on the first-of-the-month, twelve-month average prices for oil, NGLs and gas, of $50.16 per Bbl of oil, $15.13 per Bbl of NGLs and $2.64 per MMBtu of natural gas, adjusted for basis differentials, grade and quality. PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. The following table reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP. (in millions) December 31, 2015 PV-10 $ 504 Less income taxes: Undiscounted future income taxes (307) 10% discount factor 263 Future discounted income taxes (44) Standardized measure of discounted future net cash flows $ 460
  • 30. Contact information SUZANNE OGLE Vice President – Investor Relations & Corporate Communications 817.989.9000 ir@approachresources.com www.approachresources.com