Approach Resources Inc. Reports Fourth Quarter and Full-Year 2015 Results and Provides 2016 Outlook

Approach Resources Inc. (NASDAQ:AREX) today reported results for fourth quarter and full-year 2015 and estimated 2015 proved reserves.

Balance Sheet Highlights

• No capital expenditures in the fourth quarter allowed for free cash flow and debt reduction
• Reduced current liabilities from $45.2 million at 9/30/15 to $28.5 million at 12/31/15
• Reduced total debt from $515.6 million at 9/30/15 to $496.6 million at 12/31/15
• Liquidity of over $175 million at 12/31/15

Fourth Quarter 2015 Highlights

• Production was 14.5 MBoe/d, a 4% decrease from the prior-year quarter
• Revenues totaled $25.5 million, EBITDAX (non-GAAP) was $27.0 million
• Adjusted net loss (non-GAAP) was $5.0 million, or $0.12 per diluted share
• Per-unit cash operating expenses (non-GAAP) decreased 26% from the prior-year quarter, and 4% from third quarter 2015, to $10.01 per Boe
• No capital expenditures were incurred during the quarter

Full-Year 2015 Highlights

• Production was 15.2 MBoe/d, a 10% increase over the prior year
• Revenues were $131.3 million, EBITDAX (non-GAAP) was $123.6 million
• Adjusted net loss (non-GAAP) was $15.0 million, or $0.37 per diluted share
• Capital expenditures of $151.2 million

2015 Proved Reserves and Operations Highlights

• Year-end 2015 proved reserves were 166.6 MMBoe, a 14% increase over the prior year
• PV-10 (non-GAAP) was $504 million, reserve replacement ratio of 603%
• Drill-bit finding and development (non-GAAP) cost of $4.32 per Boe
• Drilled 20 horizontal wells and placed 28 horizontal wells on production during the first eight months of 2015
• Recent horizontal Wolfcamp wells tracking 45% above typecurve

Adjusted net (loss) income, EBITDAX, cash operating expenses, PV-10 and drill-bit finding and development (“F&D”) cost are non-GAAP measures. See “Supplemental Non-GAAP Financial and Other Measures” below for our definitions and reconciliations of adjusted net (loss) income and EBITDAX to net (loss) income, cash operating expenses to operating expenses and PV-10 to the standardized measure (GAAP) and our definition and calculation of liquidity, reserve replacement ratio and drill-bit F&D cost.

Management Comment

Ross Craft, Approach’s Chairman and CEO commented, “2015 proved to be another challenging year for the industry, as further deteriorating commodity prices continued to put pressure on all North American producers. However, despite the formidable commodity price environment, I am pleased to report that Approach was once again able to grow annual production and reserves to record levels, all while operating under a significantly reduced capital budget, which speaks to the quality of our assets and people. Importantly, we also made considerable progress during the year toward streamlining our corporate cost structure and further improving our industry-leading Permian Basin horizontal drilling and completion costs to $3.7 million per well based on current AFEs. We anticipate additional cost savings going forward.

While we remain hopeful that a correction in global supply/demand fundamentals will begin to drive a commodity price recovery in the second half of 2016, current signs point to continued, near-term price weakness. With that in mind, we have established a 2016 capital budget range of $20 million to $80 million, depending on the direction of commodity prices. This flexible plan will allow us to target our capital spending closer to cash flow while preserving liquidity.”

Fourth Quarter 2015 Results

Production for fourth quarter 2015 totaled 1,330 MBoe (14.5 MBoe/d), made up of 30% oil, 32% NGLs and 38% natural gas. Average realized commodity prices for fourth quarter 2015, before the effect of commodity derivatives, were $37.60 per Bbl of oil, $10.20 per Bbl of NGLs and $2.02 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $30.11 per Boe for fourth quarter 2015.

Net loss for fourth quarter 2015 was $5.8 million, or $0.14 per diluted share, on revenues of $25.5 million. Net loss for fourth quarter 2015 also included an unrealized loss on commodity derivatives of $10.3 million, a realized gain on commodity derivatives of $14.6 million, and a gain on debt extinguishment of $9.1 million. Excluding the unrealized loss on commodity derivatives and gain on debt extinguishment, adjusted net loss (non-GAAP) for fourth quarter 2015 was $5.0 million, or $0.12 per diluted share. EBITDAX (non-GAAP) for fourth quarter 2015 was $27.0 million, or $0.66 per diluted share. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net (loss) income and EBITDAX to net (loss) income.

Lease operating expenses averaged $5.44 per Boe. Production and ad valorem taxes averaged $1.94 per Boe, or 10.1% of oil, NGL and gas sales. Exploration costs were $0.17 per Boe. Cash general and administrative costs averaged $2.63 per Boe. Depletion, depreciation and amortization expense averaged $17.42 per Boe. Interest expense totaled $6.4 million.

Full-Year 2015 Results

Production for 2015 increased 10% to 5,532 MBoe (15.2 MBoe/d), made up of 34% oil, 31% NGLs and 35% natural gas. Average realized commodity prices for 2015, before the effect of commodity derivatives, were $43.65 per Bbl of oil, $12.06 per Bbl of NGLs and $2.45 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $33.23 per Boe for 2015.

Net loss for 2015 was $174.1 million, or $4.30 per diluted share, on revenues of $131.3 million. Net loss for 2015 included an unrealized loss on commodity derivatives of $33.2 million, a realized gain on commodity derivatives of $52.5 million, impairment expense of $220.2 million, rig termination fees of $2.2 million, costs of $1.4 million related to a reduction in our workforce, and a gain on debt extinguishment of $10.6 million. Excluding the unrealized loss on commodity derivatives, impairment expense, rig termination fees, workforce reduction related costs and gain on debt extinguishment, adjusted net loss (non-GAAP) for 2015 was $15.0 million, or $0.37 per diluted share. EBITDAX (non-GAAP) for 2015 was $123.6 million, or $3.05 per diluted share. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net (loss) income and EBITDAX to net (loss) income.

Lease operating expenses averaged $5.24 per Boe. Production and ad valorem taxes averaged $2.00 per Boe, or 8.4% of oil, NGL and gas sales. Exploration costs were $0.80 per Boe. Cash general and administrative costs averaged $3.68 per Boe. Depletion, depreciation and amortization expense averaged $19.76 per Boe. Interest expense totaled $25.1 million.

Operations Update

In August 2015, we elected to temporarily suspend drilling and completion operations to preserve capital during the commodity price downturn. There were no wells drilled or completed in fourth quarter 2015. During 2015, we drilled a total of 20 horizontal wells and completed 28 horizontal wells. Of these, 10 wells were drilled to the B bench and 10 wells were drilled to the C bench. At December 31, 2015, we had five horizontal wells waiting on completion. Wells completed during the third quarter using our enhanced completion design continue to outperform our current typecurve, with 150-day average production rates tracking approximately 45% above the typecurve. We continue to analyze production from these wells and expect to apply the enhanced completion techniques to all wells going forward.

Fourth Quarter and Full-Year 2015 Production

Estimated fourth quarter 2015 production totaled 1,330 MBoe (14.5 MBoe/d), a 4% decrease from fourth quarter 2014. Estimated full-year 2015 production totaled 5,532 MBoe (15.2 MBoe/d), a 10% increase over 2014.

2015 Estimated Proved Reserves and Costs Incurred

Year-end 2015 proved reserves totaled 166.6 MMBoe, up 14% from year-end 2014 proved reserves of 146.2 MMBoe. Year-end 2015 proved reserves were 33% oil, 30% NGLs and 37% natural gas, compared to 38% oil, 28% NGLs and 34% natural gas at year-end 2014.

Proved developed reserves represent approximately 37% of total year-end 2015 proved reserves, compared to 41% at year-end 2014. At December 31, 2015, 99.9% of our proved reserves were located in our core operating area in the southern Midland Basin. Year-end 2015 estimated proved reserves included 154.6 MMBoe attributable to the horizontal Wolfcamp shale play, compared to 124.8 MMBoe at year-end 2014, a 24% increase.

The table below illustrates the growing predominance of our horizontal Wolfcamp reserves over the last three years ended December 31, 2015, 2014 and 2013.

During 2015, we recorded downward revisions totaling 8.7 MMBoe, including the reclassification of 11.9 MMBoe of proved reserves. Revisions also included 13 MMBoe of positive revisions resulting from cost reductions, updated well performance and technical parameters, offset by 9.8 MMBoe of negative revisions due to lower commodity prices.

The following table summarizes the changes in our estimated proved reserves during 2015.

Our preliminary, unaudited estimate of the standardized after-tax measure of discounted future net cash flows (“standardized measure”) of our proved reserves at December 31, 2015, was $460 million. The PV-10, or pre-tax present value of our proved reserves discounted at 10%, of our proved reserves at December 31, 2015,was $504 million, compared to $1.4 billion at year-end 2014. The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2015 proved reserves and PV-10. PV-10 is a non-GAAP measure. See “Supplemental Non-GAAP Financial and Other Measures” below for our definition of PV-10 and a reconciliation to the standardized measure (GAAP). Estimates of year-end 2015 proved reserves and PV-10 were prepared using $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.

Capital expenditures incurred during 2015 totaled $151.2 million and included $139.1 million for drilling and completion activities, $11.4 million for infrastructure projects and equipment and $0.7 million for lease extensions.

2016 Guidance

The table below sets forth the Company’s production and operating costs and expenses guidance for 2016 under a $20 million capital budget scenario. Under this plan, we would drill six and complete five wells, with the flexibility to increase or decrease the number of drilled and completed wells depending on market conditions.

The table below illustrates potential activity levels and production forecasts under various capital budget scenarios.

As further discussed below under “Forward-Looking and Cautionary Statements,” the Company’s guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control. In addition, our 2016 capital budget excludes acquisitions and lease extensions and renewals and is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil, NGLs and natural gas, results of horizontal drilling and completions, economic and industry conditions at the time of drilling, the availability of sufficient capital resources for drilling prospects, the Company’s financial results and the availability of lease extensions and renewals on reasonable terms.

Liquidity Update

At December 31, 2015, we had a $1 billion senior secured revolving credit facility in place. The borrowing base and lender commitment amount were set at $450 million following the fall 2015 bank redetermination. At December 31, 2015, our liquidity and long-term debt-to-capital ratio were approximately $177.3 million and 45.0%, respectively. See “Supplemental Non-GAAP Financial and Other Measures” below for our definitions and calculation of liquidity and long-term debt-to-capital.

Commodity Derivatives Update

We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. The table below is a summary of our current derivatives positions.

Conference Call Information and Summary Presentation

The Company will host a conference call on Friday, March 4, 2016, at 9:00 a.m. Central Time (10:00 a.m. Eastern Time) to discuss fourth quarter and full-year 2015 financial and operational results. Those wishing to listen to the conference call, may do so by visiting the Events page under the Investor Relations section of the Company’s website, www.approachresources.com, or by phone:

In addition, a fourth quarter and full-year 2015 summary presentation will be available on the Company’s website.

About Approach Resources

Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and natural gas reserves in the Midland Basin of the greater Permian Basin in West Texas. For more information about the Company, please visit www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

This press release 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 press release 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 press release specifically include expectations of anticipated financial and operating results. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “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. Further information on such assumptions, risks and uncertainties is available in the Company’s Securities and Exchange Commission (“SEC”) filings. The Company’s SEC filings are available on the Company’s website at www.approachresources.com. 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.

Supplemental Non-GAAP Financial and Other Measures

This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations below of the non-GAAP financial measures to the most directly comparable GAAP financial measures and on the Non-GAAP Financial Information page in the Investor Relations section of our website at www.approachresources.com.

Adjusted Net (Loss) Income

This release contains the non-GAAP financial measures adjusted net (loss) income and adjusted net (loss) income per diluted share, which exclude (1) unrealized loss (gain) on commodity derivatives, (2) rig termination fees, (3) impairment of oil and gas properties, (4) termination costs, (5) gain on debt extinguishment, and (6) related income tax effect. 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 (loss) income and adjusted net (loss) income per diluted share are useful to investors because they provide readers with a 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 table below provides a reconciliation of adjusted net (loss) income to net (loss) income for the three and twelve months ended December 31, 2015 and 2014 (in thousands, except per-share amounts).

EBITDAX

We define EBITDAX as net (loss) income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) impairment of oil and gas properties, (5) unrealized loss (gain) on commodity derivatives, (6) gain on debt extinguishment, (7) termination costs, (8) interest expense, net, and (9) income tax (benefit) provision. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

The table below provides a reconciliation of EBITDAX to net (loss) income for the three and twelve months ended December 31, 2015 and 2014 (in thousands, except per-share amounts).

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 table below provides a reconciliation of cash operating expenses to operating expenses for the three and twelve months ended December 31, 2015 and 2014 (in thousands, except per-Boe amounts).

PV-10

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, 12-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 table below 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.

Finding and Development (“F&D”) Costs

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 the above measures of 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 or before March 15, 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 table below reconciles our estimated F&D costs for 2015 to the information required by paragraphs 11 and 21 of ASC 932-235:

Liquidity

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 December 31, 2015 and 2014 (in thousands).

Long-Term Debt-to-Capital

Long-term debt-to-capital ratio is calculated by dividing long-term debt (GAAP) by the sum of total stockholders’ equity (GAAP) and long-term debt (GAAP). We use the long-term debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio has limitations. This ratio can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the ratio on a company’s financial statements. This ratio 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 long-term debt-to-capital ratio at December 31, 2015 and 2014 (in thousands).

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Approach Resources Inc.
Sergei Krylov, 817.989.9000
Executive Vice President & Chief Financial Officer
ir@approachresources.com