First Quarter 2015 Results MAY 6, 2015 Exhibit 99.2 |
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 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. First Quarter 2015 Results – May 2015 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. |
Company overview AREX OVERVIEW ASSET OVERVIEW Enterprise value $804MM High-quality reserve base 146 MMBoe proved reserves 66% Liquids, 38% oil $1.4 BN proved PV-10 Permian core operating area 147,000 gross (134,000 net) acres ~1+ BnBoe gross, unrisked resource potential ~2,000 Identified HZ drilling locations targeting Wolfcamp A/B/C 2015 Capital program focused on flexibility and returns Running an average of 1 HZ rig in the Wolfcamp shale play with a capital budget of approximately $160 MM Note: Proved reserves as of 12/31/2014 and acreage as of 3/31/2015. 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 $8.48 per share on 5/5/2015, plus net debt as of 3/31/2015. See “PV-10 (unaudited)” slide. 3 First Quarter 2015 Results – May 2015 |
1Q15 Key highlights 4 1Q15 HIGHLIGHTS • Drilled 8 and completed 13 HZ wells • Continued improvement on already best-in- class HZ well costs • Increased 1Q15 production 21% YoY to 14.3 MBoe/d • Water recycle center now fully operational • Cash operating cost of $12.32/Boe, a 27% improvement YoY 1Q15 SUMMARY RESULTS Production (MBoe/d) 14.3 % Oil 38% % Total liquids 67% Average realized price ($/Boe) Average realized price, excluding commodity derivatives impact $ 25.87 Average realized price, including commodity derivatives impact 38.23 Costs and expenses ($/Boe) LOE $ 5.55 Production and ad valorem taxes 2.20 Exploration 0.85 General and administrative 6.30 G&A – cash component 4.58 G&A – noncash component 1.72 DD&A 20.61 Note: See “Cash operating expenses” slide. First Quarter 2015 Results – May 2015 |
Well prepared for commodity price cycle 5 Key areas of focus in 2015 • Plan to stay nimble in 2015 with key focus on financial discipline and returns • No significant drilling or service contract obligations • Plan to time and size the development budget based on magnitude of service cost reductions and direction of commodity prices • Operating team’s top priority is service cost reduction • Current well AFEs at ~$4.6 MM • Lower D&C costs significantly improves break-even price threshold • Water recycle center became fully operational during March 2015 • Strong balance sheet ensures financial flexibility • Debt / LTM EBITDAX of 2.6x • Liquidity of $240 MM at 3/31/2015 • Borrowing base of $525 MM vs elected commitment of $450 MM provides further protection to liquidity • Solid hedge book in place for 2015 First Quarter 2015 Results – May 2015 |
1Q15 Operating highlights OPERATING HIGHLIGHTS Maximizing Returns • Successfully implemented cost reduction initiatives, current HZ well AFEs now averaging $4.6 MM per well, down ~15% from 2014 average of $5.5 MM • D&C cost savings includes $450,000 per well of permanent savings from water recycling • LOE of $5.55/Boe, improved 25% YoY Tracking Development Plan • Drilled 8 HZ wells and completed 13 HZ wells • Wolfcamp B – 7 wells and Wolfcamp C – 6 wells • Recent HZ Wolfcamp average IP 723 Boe/d (56% oil, 80% liquids) • Overall HZ well results continue to track at or above increased 510 MBoe type curve Delivering Production Growth • Total production 14.3 MBoe/d (up 21% YoY) • Oil production 5.5 Mbbl/d (up 10% YoY) 6 First Quarter 2015 Results – May 2015 |
1Q15 Financial highlights FINANCIAL HIGHLIGHTS Preserving Cash Flow • Quarterly EBITDAX (non-GAAP) of $33.4 MM, or $0.83 per diluted share • Capital expenditures of $74.6 MM ($68 million for D&C) • Remain well-hedged for the balance of 2015 Stable Financial Position • Liquidity of $240MM at March 31 st • Lenders reaffirmed $450 MM commitment amount following Spring 2015 redetermination Heightened focus on cutting costs • Revenues (pre-hedge) of $33.3 MM, adjusted net loss (non-GAAP) of $1.3 MM, or $0.03 per diluted share • Every per-unit cash cost metric has been improved since 1Q14 • 1Q15 Cash operating costs totaled $12.32/Boe, a 27% decrease compared to 1Q14 Strong Balance Sheet and Liquidity to Develop HZ Wolfcamp Shale Note: See “Adjusted Net Income,” “EBITDAX,” “Strong, Simple Balance Sheet, and “Cash operating expenses” slides. 7 First Quarter 2015 Results – May 2015 |
8 Winter storms and DCP plant turnaround impact 1H15 production by 120 – 160 MBoe Winter storm related downtime ~20 MBoe 1H15 Daily Production Detail 1 2 2 2 2 2 1Q15 Wells turned to sales 1Q15 Production = 1,287 MBoe 2Q15E Production ~ 1,300 – 1,400 MBoe DCP Plant turnaround ~75 – 115 MBoe DCP Plant maintenance ~25 MBoe 3 2 2Q15E Wells turned to sales 3 4 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 1/1 1/8 1/15 1/22 1/29 2/5 2/12 2/19 2/26 3/5 3/12 3/19 3/26 4/2 4/9 4/16 4/23 4/30 5/7 5/14 5/21 5/28 6/4 6/11 6/18 6/25 First Quarter 2015 Results – May 2015 |
9 AREX Flowback and Produced Water Recycle Facility • Reduce drilling and completion cost by $450K per well • Reduce LOE by up to $1.00 per BOE • Eliminate usage of potable fresh water for completion • Minimize surface disturbance • Skim oil sale up to 200 Bbls per day - more than sufficient to pay for facility operating expense 329,000 Bbl Capacity Facility Skim Oil Sales Flowback & Produced Water Offloading Terminal & Separation Facility Flowback & Produced Water Supply 90 BPM Pump Station Water Treatment & Filtration Facility 63,000 BBL Treated Water Tank 44,000 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 32,000 BBL Dirty Water Tank 32,000 BBL Treated Water Tank First Quarter 2015 Results – May 2015 |
10 Water recycling facility successfully started in March 2015 Recent Recycled Water Volumes • The water recycling facility was ramped up during March 2015 and now successfully recycles up to 70+% of AREX daily flowback water volumes 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0 5,000 10,000 15,000 20,000 25,000 30,000 3/21 3/28 4/4 4/11 First Quarter 2015 Results – May 2015 |
Strong, simple balance sheet 11 AREX Liquidity and Capitalization • At March 31, 2015, we had a $1 billion senior secured revolving credit facility in place, with aggregate lender commitments of $450 MM and borrowing base of $600 MM • Following the Spring 2015 redetermination, our lenders reaffirmed the commitment amount of $450 MM, while reducing the borrowing base to $525 MM • A $75 MM cushion remains against more conservative bank lending framework • Manageable Debt / LTM EBITDAX of 2.6x • LTM EBITDAX / LTM Interest of 8.0x, well above minimum 2.5x covenant requirement • Simple balance sheet with no near-term debt maturities AREX Debt Maturity Schedule ($ MM) AREX Capitalization as of 3/31/2015 ($ MM) Cash $0.3 Credit Facility 210.0 7.0% Senior Notes due 2021 250.0 Total Long-Term Debt $460.0 Shareholders’ Equity 768.8 Total Book Capitalization $1,228.8 AREX Liquidity as of 3/31/2015 Aggregate Commitment $450.0 Cash and Cash Equivalents 0.3 Borrowings under Credit Facility (210.0) Undrawn Letters of Credit (0.3) Liquidity $240.0 $240 MM undrawn borrowing capacity 7.0% Senior Notes $0.0 $50.0 $100.0 $150.0 $200.0 $250.0 $300.0 $350.0 $400.0 $450.0 2015 2016 2017 2018 2019 2020 2021 $210.0 $250.0 First Quarter 2015 Results – May 2015 |
Valuation and leverage well supported by proved reserve base 12 • 12/31/2014 reserve summary prepared by DeGolyer and MacNaughton • Replaced 819% of produced reserves at a drill-bit F&D cost of $8.94 per Boe¹ • Total proved reserves up 27% YoY, proved oil reserves up 20% YoY • PV-10 up 25% YoY to a record $1.4 billion Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) PV-10 ($ MM)² PDP 17,599 18,319 133,583 58,181 $870.0 PDNP 379 763 5,378 2,039 $12.4 PUD 37,360 21,825 161,059 86,028 $530.6 Total Proved 55,338 40,907 300,020 146,248 $1,413.0 Total Proved Reserves Reserves by Commodity Proved PV-10 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. 2. PV-10 calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and natural gas, of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu of natural gas. 38% 28% 34% 40% 1% 59% 62% < 1% 38% Oil NGLs Natural Gas PDP PDNP PUD PDP PDNP PUD First Quarter 2015 Results – May 2015 |
13 Significant valuation upside potential from unproven resources and commodity price recovery Adjusted PV-10 vs Enterprise Value ($ billion) Midland Basin Peer EV/2015E EBITDA 6 1 1. Using SEC prices of $94.56/Bbl for WTI and $4.55/Mcf for Henry Hub. 2. Based on NYMEX strip prices for WTI and Henry Hub as of 5/5/2015. 3. Assumes D&C cost of $4.6MM per horizontal PUD well. 4. 1Q15 capex of $74.6MM. 5. PV-10 as of 12/31/14 is reconciled to our standardized measure of discounted future cash flows, the most directly comparable measure calculated and presented in accordance with GAAP, on slide 26. Adjusted PV-10 is calculated consistent with PV-10 as of 12/31/14, adjusted for the following: (1) NYMEX strip prices as of 5/5/14, (2) D&C cost of $4.6MM per horizontal PUD well location, and (3) 1Q15 capex of $74.6MM. 6. Enterprise value/2015E EBITDA per FactSet consensus as of 5/5/2015. Peers include CPE, FANG, LPI, PE, PXD, RSPP. 2 3 4 5 First Quarter 2015 Results – May 2015 $1.4 ($0.7) $0.1 $0.1 $0.8 $0.8 $0.0 $0.2 $0.4 $0.6 $0.8 $1.0 $1.2 $1.4 YE2014 Proved SEC PV-10 Commodity Price Decline Impact D&C Cost Savings Impact 1Q15 Net Investment Adjusted Proved Enterprise PV-10 Current Value 5.1x 8.4x 10.9x 11.0x 13.9x 14.9x 18.2x 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 12.0x 14.0x 16.0x 18.0x 20.0x AREX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 |
14 AREX HZ WOLFCAMP (BOE/D) AREX HZ Wolfcamp Well Performance Oil EUR = 230 MBBL Well EUR = 510 MBOE Gas EUR = 1,271 MMCF Average GOR = 5,000 – 6,000 Average Oil Average BOE Average Gas Average GOR N = 93 Wells AREX Wolfcamp Horizontal Type Curve Year-end 2014 First Quarter 2015 Results – May 2015 Note: Daily production normalized for operational downtime. Gas EUR is unprocessed wellhead volume. |
Probability Distribution of AREX 93 Type Curve Wells at Year-end 2014 15 First Quarter 2015 Results – May 2015 |
Proven track record of delivering lowest D&C cost in the Midland Basin 16 Approach’s annual average horizontal well D&C cost Demonstrated 35% improvement 2011-2014 Achieved 16% D&C cost reduction First Quarter 2015 Results – May 2015 $ MM $8.6 $7.0 $5.8 $5.5 $4.6 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 2011 2012 2013 2014 Current AFE |
D&C Cost reductions will significantly improve profitability 17 Note: HZ Wolfcamp economics assume $4.00/Mcf realized natural gas price and NGL price based on 40% of realized oil price. IRR at NYMEX strip pricing First Quarter 2015 Results – May 2015 0% 10% 20% 30% 40% 50% 60% 70% $40 $50 $60 $70 $80 $90 Realized Oil Price ($/Bbl) $4.1MM D&C $4.6MM D&C $5.1MM D&C $5.5MM D&C |
Established infrastructure in place is critical to low cost structure 18 Benefits of water recycling Pangea West North & Central Pangea South Pangea Schleicher Crockett Irion Reagan Sutton Recently completed water recycling facility 329,000 Bbl Capacity • Reduce D&C cost • Reduce LOE • Increase project profit margin • Minimize fresh water use, truck traffic and surface disturbance First Quarter 2015 Results – May 2015 |
Current hedge position 19 Commodity & Period Contract Type Volume Contract Price Crude Oil April 2015 – December 2015 Collar 1,600 Bbls/d $84.00/Bbl - $91.00/Bbl April 2015 – December 2015 Collar 1,000 Bbls/d $90.00/Bbl - $102.50/Bbl April 2015 – December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $94.00/Bbl April 2015 – December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $95.00/Bbl Natural Gas April 2015 – June 2015 Collar 80,000 MMBtu/month $4.00/MMBtu - $4.74/MMBtu April 2015 – December 2015 Swap 200,000 MMBtu/month $4.10/MMBtu April 2015 – December 2015 Collar 130,000 MMBtu/month $4.00/MMBtu - $4.25/MMBtu • Based on the midpoint of current 2015 guidance, approximately 56% of forecasted 2Q15-4Q15 oil production and 42% of forecasted natural gas production are hedged at weighted average floor prices of $79.83/Bbl and $4.06/MMBtu, respectively. First Quarter 2015 Results – May 2015 |
Production and expense guidance 20 2015 Guidance Production Oil (MBbls) 2,200 – 2,325 NGLs (MBbls) 1,575 – 1,625 Natural Gas (MMcf) 10,050 – 10,200 Total (MBoe) 5,450 – 5,650 Operating costs and expenses (per Boe) Lease operating $6.00 - $7.00 Production and ad valorem taxes 7.25% of oil & gas revenues Cash general and administrative $3.75 - $4.25 Exploration (non-cash) $0.50 - $1.00 Depletion, depreciation and amortization $20.00 - $22.00 Capital expenditures (in millions) ~$160 First Quarter 2015 Results – May 2015 |
Appendix |
Adjusted net income (unaudited) 22 (in thousands, except per-share amounts) Three Months Ended March 31, 2015 2014 Net (loss) income $ (7,708) $ 2,945 Adjustments for certain items: Unrealized loss on commodity derivatives 9,321 5,926 Rig termination fees 498 - Related income tax effect (3,437) (2,015) Adjusted net (loss) income $ (1,326) $ 6,856 Adjusted net (loss) income per diluted share $ (0.03) $ 0.17 The amounts included in the calculation of adjusted net (loss) income and adjusted net (loss) 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. The following table provides a reconciliation of adjusted net (loss) income to net income for the three months ended March 31, 2015 and 2014. ADJUSTED NET (LOSS) INCOME (UNAUDITED) First Quarter 2015 Results – May 2015 |
EBITDAX (unaudited) 23 EBITDAX (UNAUDITED) The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is not a measure of net income or cash flow as determined by 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. The following table provides a reconciliation of EBITDAX to net income for the three months ended March 31, 2015 and 2014. (in thousands, except per-share amounts) Three Months Ended March 31, 2015 2014 Net (loss) income $ (7,708) $ 2,945 Exploration 1,090 738 Depletion, depreciation and amortization 26,520 23,606 Share-based compensation 2,217 2,654 Unrealized loss on commodity derivatives 9,321 5,926 Interest expense, net 5,922 5,137 Income tax (benefit) provision (3,996) 1,681 EBITDAX $ 33,366 $ 42,687 EBITDAX per diluted share $ 0.83 $ 1.09 First Quarter 2015 Results – May 2015 |
F&D costs (unaudited) 24 F&D Cost reconciliation Cost summary (in thousands) Property acquisition costs Unproved properties $ 4,578 Proved properties - Exploration costs 3,831 Development costs 382,995 Total costs incurred $ 391,404 Reserves summary (MBoe) Balance – 12/31/2013 114,661 Extensions & discoveries 43,247 Production (1) (5,281) Revisions to previous estimates (6,379) Balance – 12/31/2014 146,248 F&D cost ($/Boe) All-in F&D cost $ 10.62 Drill-bit F&D cost 8.94 Reserve replacement ratio Drill-bit 819% 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 to be included in our annual report on Form 10-K to be filed with the SEC on February 26, 2015. 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 2014 to the information required by paragraphs 11 and 21 of ASC 932-235. (1) Production includes 1,390 MMcf related to field fuel. First Quarter 2015 Results – May 2015 |
PV-10 (unaudited) 25 The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $1.4 billion at December 31, 2014, and was calculated based on the first-of-the-month, twelve-month average prices for oil, NGLs and gas, of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu of natural gas. 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, 2014 PV-10 $ 1,413 Less income taxes: Undiscounted future income taxes (1,267) 10% discount factor 910 Future discounted income taxes (357) Standardized measure of discounted future net cash flows $ 1,056 First Quarter 2015 Results – May 2015 |
Cash operating expenses 26 Cash operating expenses 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, 2015 and 2014. (in thousands, except per-Boe amounts) Three Months Ended March 31, 2015 2014 Operating expenses $ 45,686 $ 44,899 Exploration (1,090) (738) Depletion, depreciation and amortization (26,520) (23,606) Share-based compensation (2,217) (2,654) Cash operating expenses $ 15,859 $ 17,901 Cash operating expenses per Boe $ 12.32 $ 16.78 First Quarter 2015 Results – May 2015 |
Contact information SERGEI KRYLOV Executive Vice President & Chief Financial Officer 817.989.9000 ir@approachresources.com www.approachresources.com |