Attached files
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| 8-K - 8-K - Approach Resources Inc | d98847d8k.htm |
| EX-99.1 - EX-99.1 - Approach Resources Inc | d98847dex991.htm |
 Third Quarter 2015 Results NOVEMBER 4, 2015 Exhibit 99.2 |
 Forward-looking statements 2 Cautionary statements regarding oil & gas quantities Third Quarter 2015 Results – November 2015 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. |
 Company overview AREX OVERVIEW ASSET OVERVIEW Enterprise value $630MM High-quality reserve base 146 MMBoe proved reserves 66% Liquids, 38% oil $1.4 BN proved PV-10 Permian core operating area 142,000 gross (130,000 net) acres ~1+ BnBoe gross, unrisked resource potential ~2,000 Identified HZ drilling locations targeting Wolfcamp A/B/C Capital program focused on flexibility and returns - Aligned capital spending with cash flow - Cost reductions improving drilling IRRs - With limited land obligations and no service contracts, capital spending program is largely discretionary 3 Third Quarter 2015 Results – November 2015 Note: Proved reserves as of 12/31/2014 and acreage as of 9/30/2015. 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 $2.82 per share on 11/3/2015, plus net debt as of 9/30/2015. See “PV-10 (unaudited)” slide.
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 3Q15 Key highlights 4 3Q15 HIGHLIGHTS • Drilled 4 and completed 5 HZ wells • Continued improvement on already best-in- class cost structure • Increased 3Q15 production 17% YoY to 16.6 MBoe/d • Reduced cash operating cost 18% YoY to $10.45/Boe • Reduced LOE 14% YoY to $5.04/Boe 3Q15 SUMMARY RESULTS Production (MBoe/d) 16.6 % Oil 32% % Total liquids 64% Average realized price ($/Boe) Average realized price, excluding commodity derivatives impact $ 22.26 Average realized price, including commodity derivatives impact 30.62 Costs and expenses ($/Boe) LOE $ 5.04 Production and ad valorem taxes 1.77 Exploration 1.28 General and administrative 4.77 G&A – cash component 3.65 G&A – noncash component 1.12 DD&A 20.47 Note: See “Cash operating expenses” slide. Third Quarter 2015 Results – November 2015 |
 3Q15 Operating highlights Maximizing Returns • LOE of $5.04/Boe, improved 14% YoY • Implemented further cost saving initiatives which should lower LOE and G&A by $5 -
$7MM annually starting FY2016
• 3Q15 Cash operating costs totaled $10.45/Boe, an 18% decrease compared to 3Q14
and a 5% improvement over 2Q15
Tracking Development Plan • Drilled 4 HZ wells and completed 5 HZ wells, with 4 wells currently waiting on completion • Wolfcamp B – 3 wells and Wolfcamp C – 2 wells • 3Q15 HZ Wolfcamp average IP 931 Boe/d (65% oil, 84% liquids) Delivering Production Growth • Record total quarterly production of 16.6 MBoe/d (up 10% QoQ) • Quarterly oil production of 5.3 MBbl/d 5 Note: See “Cash operating expenses” slide. Third Quarter 2015 Results – November 2015 OPERATING HIGHLIGHTS |
 3Q15 Financial highlights Preserving Cash Flow • Quarterly EBITDAX (non-GAAP) of $30.7 MM, or $0.76 per diluted share • Capital expenditures of $19.8 MM ($17.9 MM for D&C) • Remain well-hedged for the balance of 2015, added 2016 gas hedges Stable Financial Position • Liquidity of $172MM at September 30 th • Following recent Fall 2015 redetermination, lender commitments and borrowing base
set at $450 MM Continued Focus on Cutting Costs • Revenues (pre-hedge) of $33.9 MM, $46.7 MM with hedges • Adjusted net loss (non-GAAP) of $5.9 MM, or $0.14 per diluted share • Every per-unit cash cost metric has improved by double-digits since 3Q14
6 Third Quarter 2015 Results – November 2015 Note: See “Adjusted Net Income,” “EBITDAX,” and “Strong, Simple Balance Sheet” slides.
FINANCIAL HIGHLIGHTS |
 Lowest cost structure in the Permian Basin 7 $7.36 $6.18 $5.87 $6.65 $5.55 $4.97 $5.04 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 AREX LOE Historical Track Record ($/Boe) Permian Peer LOE ($/Boe) AREX D&C Historical Track Record ($ MM) Permian Peer D&C Cost ($ MM) $13.02 $9.12 $8.90 $8.12 $7.59 $7.51 $7.30 $6.90 $6.84 $6.18 $5.04 $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 $8.6 $7.0 $5.8 $5.5 $4.5 $4.2 $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 3Q15 Best Well $8.3 $7.8 $6.6 $6.6 $6.5 $6.3 $6.1 $6.1 $6.0 $5.8 $4.5 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 Source: Company presentations and public filings, peer data as of 2Q15. Peers include CPE, CWEI, CXO, EGN, FANG, LPI, MTDR, PE, PXD, and RSPP. Third Quarter 2015 Results – November 2015 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 AREX Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 AREX |
 Established infrastructure in place is critical to low cost structure
8 Benefits of water recycling • Reduce D&C cost • Reduce LOE • Increase project profit margin • Minimize fresh water use, truck traffic and surface disturbance Pangea West North & Central Pangea South Pangea Schleicher Crockett Irion Reagan Sutton Recently completed water recycling facility 329,000 Bbl Capacity Third Quarter 2015 Results – November 2015 |
 Strong, simple balance sheet 9 AREX Liquidity and Capitalization • Following the Fall 2015 redetermination, we had a $1 billion senior secured revolving credit facility in place, with aggregate lender commitments and borrowing base of $450 MM • Current liquidity of $172 MM is more than adequate given capital budget is aligned with cash flow • LTM EBITDAX / LTM Interest of 5.8x, well above minimum 2.5x covenant requirement • Current ratio of 4.2x, well above minimum 1.0x covenant requirement • No near-term debt maturities AREX Debt Maturity Schedule ($ MM) AREX Capitalization as of 9/30/2015 ($ MM) Cash $0.3 Credit Facility 275.6 7.0% Senior Notes due 2021 240.0 Total Long-Term Debt 1 $515.6 Shareholders’ Equity 611.9 Total Book Capitalization $1,127.5 AREX Liquidity as of 9/30/2015 Borrowing Base $450.0 Cash and Cash Equivalents 0.3 Borrowings under Credit Facility (278.0) Undrawn Letters of Credit (0.3) Liquidity $172.0 $172 MM undrawn borrowing capacity 7.0% Senior Notes 1. Long-term debt is net of debt issuance costs of $7.4 million as of September 30, 2015
Third Quarter 2015 Results – November 2015
$278.0 $245.0 $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 |
 D&C Cost reductions will significantly improve profitability
10 Note: HZ Wolfcamp economics assume $4.00/Mcf realized natural gas price and NGL price based on 40% of realized oil price. Third Quarter 2015 Results – November 2015 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% $40 $50 $60 $70 $80 $90 Realized Oil Price ($/Bbl) $3.5MM D&C $4.0MM D&C $4.5MM D&C |
 Current hedge position 11 Commodity & Period Contract Type Volume Contract Price Crude Oil October 2015 – December 2015 Collar 1,600 Bbls/d $84.00/Bbl - $91.00/Bbl October 2015 – December 2015 Collar 1,000 Bbls/d $90.00/Bbl - $102.50/Bbl October 2015 – December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $94.00/Bbl October 2015 – December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $95.00/Bbl October 2015 – December 2016 Swap 750 Bbls/d $62.52/Bbl Natural Gas October 2015 – December 2015 Swap 200,000 MMBtu/month $4.10/MMBtu October 2015 – December 2015 Collar 130,000 MMBtu/month $4.00/MMBtu - $4.25/MMBtu March 2016 – December 2016 Swap 200,000 MMBtu/month $2.93/MMBtu • Based on the midpoint of current 2015 guidance, approximately 88% of forecasted 4Q15 oil production and
34% of forecasted natural gas production are hedged at weighted average floor prices of
$74.78/Bbl and $4.06/MMBtu, respectively.
Third Quarter 2015 Results – November 2015
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 Production and expense guidance 12 2015 Guidance Production Oil (MBbls) 1,900 – 1,975 NGLs (MBbls) 1,575 – 1,625 Natural Gas (MMcf) 11,550 – 11,700 Total (MBoe) 5,400 – 5,550 Operating costs and expenses (per Boe) Lease operating $5.50 - $6.50 Production and ad valorem taxes 7.50% 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) ~$150 Third Quarter 2015 Results – November 2015 |
 Appendix |
 Adjusted net (loss) income (unaudited) 14 (in thousands, except per-share amounts) Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Net (loss) income $ (148,787) $ 22,447 $ (168,345) $ 29,185 Adjustments for certain items: Unrealized (gain) loss on commodity derivatives (296) (18,810) 22,929 (5,206) Rig termination fees 1,701 - 2,199 - Impairment of oil and gas properties 220,197 - 220,197 - Termination costs 1,436 - 1,436 - Gain on debt extinguishment (1,483) - (1,483) - Related income tax effect (78,623) 6,816 (86,926) 1,886 Adjusted net (loss) income $ (5,855) $ 10,453 $ (9,993) $ 25,865 Adjusted net (loss) income per diluted share $ (0.14) $ 0.27 $ (0.25) $ 0.66 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 (loss) income for the three and nine months ended September 30, 2015 and 2014. ADJUSTED NET (LOSS) INCOME (UNAUDITED) Third Quarter 2015 Results – November 2015 |
 EBITDAX (unaudited) 15 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 (loss) income for the three and nine months ended September 30, 2015 and 2014. (in thousands, except per-share amounts) Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Net (loss) income $ (148,787) $ 22,447 $ (168,345) $ 29,185 Exploration 1,956 891 4,211 3,595 Depletion, depreciation and amortization 31,222 25,959 86,146 78,138 Share-based compensation 1,708 1,965 6,000 5,726 Impairment of oil and gas properties 220,197 - 220,197 - Unrealized (gain) loss on commodity derivatives (296) (18,810) 22,929 (5,206) Gain on debt extinguishment (1,483) - (1,483) - Termination costs 1,436 - 1,436 - Interest expense, net 6,465 5,442 18,630 15,936 Income tax (benefit) provision (81,756) 12,756 (93,121) 16,590 EBITDAX $ 30,662 $ 50,650 $ 96,600 $ 143,964 EBITDAX per diluted share $ 0.76 $ 1.29 $ 2.39 $ 3.66 Third Quarter 2015 Results – November 2015 |
 Cash operating expenses 16 Cash operating expenses We define cash operating expenses as operating expenses, excluding (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) termination costs, and (5) impairment of oil and gas properties. 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 and nine months ended September 30, 2015 and 2014. (in thousands, except per-Boe amounts) Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Operating expenses $ 272,462 $ 45,525 $ 365,118 $ 141,236 Exploration (1,956) (891) (4,211) (3,595) Depletion, depreciation and amortization (31,222) (25,959) (86,146) (78,138) Share-based compensation (1,708) (1,965) (6,000) (5,726) Termination costs (1,436) - (1,436) - Impairment of oil and gas properties (220,197) - (220,197) - Cash operating expenses $ 15,943 $ 16,710 $ 47,128 $ 53,777 Cash operating expenses per Boe $ 10.45 $ 12.79 $ 11.21 $ 14.70 Third Quarter 2015 Results – November 2015 |
 F&D costs (unaudited) 17 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% (1) Production includes 1,390 MMcf related to field fuel. Third Quarter 2015 Results – November 2015 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. |
 PV-10 (unaudited) 18 (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 Third Quarter 2015 Results – November 2015 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. |
 Contact information SERGEI KRYLOV Executive Vice President & Chief Financial Officer 817.989.9000 ir@approachresources.com www.approachresources.com |