×

Approach Resources Inc. Reports 2016 Fourth Quarter and Full-Year Financial and Operating Results and Provides 2017 Outlook

FORT WORTH, Texas, March 09, 2017 (GLOBE NEWSWIRE) -- Approach Resources Inc. (NASDAQ:AREX) today reported financial and operational results for the fourth quarter and full-year 2016 and estimated 2016 proved reserves.

Fourth Quarter 2016 Highlights

  • Production was 12.0 MBoe/d, exceeding quarterly guidance
  • Record low quarterly lease operating expense (“LOE”) of $3.40 per Boe
  • Cash operating expenses decreased 14% from the prior-year quarter
  • Revenues were $26.5 million, an increase of 12% from the prior quarter

Full-Year 2016 and Other Highlights

  • Production was 12.4 MBoe/d, exceeding midpoint of annual guidance
  • Record low annual LOE of $4.24 per Boe
  • Record low drilling and completion costs of $3.5 million per well, a reduction of 22% over prior year
  • Drilled six and completed five wells using positive cash flow generated from our operations, with no increase in debt
  • We are encouraged with the results of our new generation completions and once we have additional production data we plan to update our type curves to reflect the EUR improvements
  • Reserve replacement ratio of 350%
  • Reached an agreement to reduce senior note debt by $130.6 million and future interest expense by $40 million through debt-for-equity exchange, subsequently closed in January 2017

Management Comment

Ross Craft, Approach’s Chairman and CEO commented, “In 2016, we delivered exceptional operational results while maintaining our focus on reducing costs and increasing operating efficiencies. We achieved record low LOE and drilling and completion costs during the year, and successfully managed our natural production decline. We also negotiated, and subsequently closed in January 2017, a transformational, strategic deleveraging transaction that reduced outstanding debt by $130.6 million and future interest expense by $40 million, and launched an exchange offer for our remaining $99.8 million of senior notes. We are excited to have three new board members and to align ourselves with a strategic investor that has the depth of knowledge in the oilfield services and energy business of the Wilks Family Office, our new largest shareholder. Capitalizing on the increase in commodity prices, we hedged approximately 85% of 2017 forecasted natural gas and 50% of NGL production. While continuing to operate within our cash flow in 2017, we expect to resume production growth from our year-end 2016 exit rate. We believe we are well-positioned to create value for our shareholders by strengthening our balance sheet, building on our asset base and continuing to be the lowest-cost operator in the Midland Basin.”

Fourth Quarter 2016 Results

Production for fourth quarter 2016 totaled 1,106 MBoe (12.0 MBoe/d), made up of 28% oil, 34% NGLs and 38% natural gas. Average realized commodity prices for fourth quarter 2016, before the effect of commodity derivatives, were $46.02 per Bbl of oil, $15.25 per Bbl of NGLs and $2.65 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $24.36 per Boe for fourth quarter 2016.

Net loss for fourth quarter 2016 was $13.5 million, or $0.32 per diluted share, on revenues of $26.5 million. Net loss for fourth quarter 2016 also included an unrealized loss on commodity derivatives of $3.3 million and a realized gain on commodity derivatives of $0.4 million. Excluding the unrealized loss on commodity derivatives, adjusted net loss (non-GAAP) for fourth quarter 2016 was $11.3 million, or $0.27 per diluted share, which includes a non-cash charge of $0.04 per share related to a deferred tax asset reversal arising from our share-based compensation. EBITDAX (non-GAAP) for fourth quarter 2016 was $15.5 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net loss.

LOE averaged $3.40 per Boe. Production and ad valorem taxes averaged $2.43 per Boe, or 10.1% of oil, NGLs and gas sales. Exploration costs were $0.62 per Boe. Total general and administrative (“G&A”) costs averaged $6.35 per Boe, including cash G&A costs of $4.55 per Boe. Depletion, depreciation and amortization expense averaged $17.54 per Boe. Interest expense totaled $7.1 million.

Full-Year 2016 Results

Production for 2016 was 4,537 MBoe (12.4 MBoe/d), made up of 28% oil, 34% NGLs and 38% natural gas. Average realized commodity prices for 2016, before the effect of commodity derivatives, were $37.90 per Bbl of oil, $12.93 per Bbl of NGLs and $2.14 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $21.25 per Boe for 2016.

Net loss for 2016 was $52.2 million, or $1.26 per diluted share, on revenues of $90.3 million. Net loss for 2016 included an unrealized loss on commodity derivatives of $11.6 million and a realized gain on commodity derivatives of $6.1 million. Excluding the unrealized loss on commodity derivatives and write-off of debt issuance costs of $0.6 million, adjusted net loss (non-GAAP) for 2016 was $44.3 million, or $1.07 per diluted share, which includes a non-cash charge of $0.05 per share related to a deferred tax asset reversal arising from our share-based compensation. EBITDAX (non-GAAP) for 2016 was $52 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net loss.

LOE averaged $4.24 per Boe, a 19% decrease from the prior year. Production and ad valorem taxes averaged $1.81 per Boe, or 9.1% of oil, NGLs and gas sales. Exploration costs were $0.86 per Boe. Total G&A costs averaged $5.45 per Boe, including cash G&A costs of $4.07 per Boe. Depletion, depreciation and amortization expense averaged $17.42 per Boe. Interest expense totaled $27.3 million.

Adjusted net loss, EBITDAX, cash operating expenses and PV-10 are non-GAAP measures. See “Supplemental Non-GAAP Financial and Other Measures” below for our definitions and reconciliations of adjusted net loss and EBITDAX to net loss, cash operating expenses to operating expenses and PV-10 to the standardized measure (GAAP) and our definition and calculation of liquidity.

Operations Update

In 2016, we focused on operating within cash flow while managing natural production decline, improving cost structure and increasing efficiencies. During 2016, we drilled a total of six horizontal wells and completed five. Of these, two wells were drilled to the A bench, one well was drilled to the B bench and three wells were drilled to the C bench. The five completed wells are tracking at a type curve of approximately 678 Mboe, including one well normalized for a 7,500 foot lateral length. At December 31, 2016, we had six horizontal wells waiting on completion.

With our new generation frac design, we are very encouraged by the well results and expect to update our type curves to reflect the EUR improvements once we have additional production data. We currently are running one horizontal rig in Project Pangea and have completed two University wells that are in the early stage of flowback.

We managed our natural production decline through surface facility optimization, operating efficiencies and investment in well repairs, workovers and maintenance. During the first quarter of 2016, our production decreased by 12% compared to the prior quarter due to no new well completions from August 2015 through first quarter 2016, and the reservoir’s natural production decline. After the first quarter 2016, further production decline was limited to 1%, 3% and 1% in the second, third and fourth quarters of 2016, respectively.

Our extensive infrastructure network of centralized production facilities, water transportation, handling and recycling system, gas lift lines and salt water disposal wells continue to provide competitive advantages in driving down drilling and completion, and operating costs. In 2016, we were able to reduce our drilling and completion costs by 22% to $3.5 million per well and LOE per Boe by 19% to $4.24 per Boe.

Strategic Deleveraging Transaction

On November 2, 2016, we entered into an exchange agreement with Wilks Brothers, LLC and SDW Investments, LLC, entities beneficially owned by the Wilks Family Office and collectively the largest holder of the Company’s 7.00% senior notes due 2021, to exchange $130.6 million principal amount of senior notes, for 39,165,600 new shares of our common stock. This exchange was completed on January 27, 2017, resulting in a reduction in principal amount of our senior notes of $130.6 million and approximately $40 million in future interest savings. The exchange ratio implied a valuation of $3.33 per share and represented a 23% premium to the closing price of our common stock on November 2, 2016, the date of the exchange agreement.

Immediately following the close of the exchange, we launched an offer to exchange our common stock for the remaining $99.8 million of our outstanding senior notes at an exchange ratio of 276 shares of common stock per $1,000 principal amount of senior notes, which we anticipate closing in the first quarter of 2017.

Fourth Quarter and Full-Year 2016 Production

Estimated fourth quarter 2016 production totaled 1,106 MBoe (12.0 MBoe/d). Estimated full-year 2016 production totaled 4,537 MBoe (12.4 MBoe/d).

Three and 12 Months Ended
December 31, 2016
Three
months
12 months
Production:
Oil (MBbls)304 1,275
NGLs (MBbls)380 1,529
Gas (MMcf)2,530 10,404
Total (MBoe)1,106 4,537
Total (MBoe/d)12.0 12.4

2016 Estimated Proved Reserves and Costs Incurred

Year-end 2016 proved reserves totaled 156.4 MMBoe. Year-end 2016 proved reserves were 32% oil, 30% NGLs and 38% natural gas. Proved developed reserves represent approximately 38% of total year-end 2016 proved reserves.

At December 31, 2016, substantially all of our proved reserves were located in our core operating area in the southern Midland Basin. Year-end 2016 estimated proved reserves included 145.4 MMBoe attributable to the horizontal Wolfcamp shale play.

The table below illustrates our horizontal Wolfcamp and other reserves over the last three years ended December 31, 2016, 2015, and 2014.

Proved Reserves (Mboe)
2016
2015
2014
Horizontal Wolfcamp
Proved developed47,861 49,843 40,678
Proved undeveloped97,502 104,790 84,138
Total145,363 154,633 124,816
Percent of total proved reserves93% 93% 85%
Other Vertical
Proved developed11,014 12,013 19,542
Proved undeveloped- - 1,890
Total11,014 12,013 21,432
Percent of total proved reserves7% 7% 15%
Total proved reserves156,377 166,646 146,248

Extensions and discoveries for 2016 were 16.7 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2016, we reclassified 22.2 MMBoe of proved undeveloped reserves that are not expected to be developed within five years under Securities and Exchange Commission (“SEC”) rules to probable reserves. Revisions also included an increase of 2.1 MMBoe of proved reserves resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 1.9 MMBoe of proved reserves due to lower commodity prices.

The following table summarizes the changes in our estimated proved reserves during 2016.

Oil
(MBbls)
NGLs
(MBbls)
Natural Gas
(MMcf)
Total
(MBoe)
Balance – December 31, 201554,496 49,486 375,988 166,646
Extensions and discoveries6,529 4,564 33,347 16,651
Production (1)(1,275) (1,529) (11,734) (4,759)
Revisions(9,719) (4,887) (45,324) (22,161)
Balance – December 31, 201650,031 47,634 352,277 156,377
Reserve replacement ratio
Extensions and discoveries / Production 350%
(1) Production includes 1,330 MMcf related to field fuel.

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, 2016, was $297.8 million. The PV-10, or pre-tax present value of our proved reserves discounted at 10%, of our proved reserves at December 31, 2016, was $307.9 million ($730.2 million at December 31, 2016 NYMEX strip).

The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2016 proved reserves and PV-10 at SEC pricing. PV-10 is a non-GAAP measure. See “Supplemental Non-GAAP Financial and Other Measures” below for our definition of PV-10 and reconciliation to the standardized measure (GAAP). Our reserve estimates and our calculation of standardized measure and PV-10 are based on the 12-month average of the first-day-of-the-month pricing of $42.69 per Bbl of oil, $14.12 per Bbl of NGLs and $2.47 per MMBtu of natural gas during 2016.

At NYMEX strip pricing at December 31, 2016, PV-10 is $730.2 million. The following table summarizes the NYMEX strip prices at December 31, 2016.

2017 2018 2019 2020 2021(1)
Oil (per Bbl)$56.19 $56.59 $56.10 $56.05 $56.21
Natural Gas (per MMBtu)$3.61 $3.14 $2.87 $2.88 $2.90
(1) Subsequent year prices were held flat for the remaining lives of the properties.
(2) NGLs prices per Bbl were estimated at 40% of the oil strip price.

Net capital expenditures incurred during 2016 totaled $19.8 million and were attributable to drilling and development ($17.8 million) and infrastructure projects and equipment ($3.1 million), and included a positive legal settlement with a service provider ($1.1 million).

Guidance

The Company’s capital budget for 2017 is a range of $50 million to $70 million depending on commodity prices. We currently are operating one rig. The table below sets forth our production and operating costs and expenses guidance for 2017.

2017 Guidance
Capital expenditures (in millions) $50 – $70


Production:
Oil (MBbls) 1,200 – 1,300
NGLs (MBbls) 1,380 – 1,460
Gas (MMcf) 9,500 – 10,160
Total (MBoe) 4,163 – 4,453
Cash operating costs (per Boe):
Lease operating$4.00 – 5.00
Production and ad valorem taxes 8.5% of oil & gas revenues
Cash general and administrative$4.00 – 5.00
Non-cash operating costs (per Boe):
Non-cash general and administrative$1.00 – 1.50
Exploration$0.50 – 1.00
Depletion, depreciation and amortization$17.00 – 19.00

First quarter 2017 production is estimated to be approximately 11.3 MBoe/d. First quarter 2017 production will be affected by no new well completions in the fourth quarter of 2016, weather and RVP pipeline specification issues in first quarter 2017. We expect to resume quarterly production growth starting in the second quarter of 2017.

As further discussed below under “Forward-Looking and Cautionary Statements,” our guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond our control. In addition, our 2017 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, our financial results and the availability of lease extensions and renewals on reasonable terms.

Liquidity Update

At December 31, 2016, we had a $1 billion senior secured revolving credit facility in place with a borrowing base of $325 million. At December 31, 2016, our liquidity and long-term debt-to-capital ratio were approximately $51.4 million and 47%, 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. At present, approximately 85% of 2017 forecasted natural gas and 50% of NGL production is hedged. The table below is a summary of our current derivatives positions.

Commodity and Period Contract
Type
Volume Transacted Contract Price
Natural Gas
January 2017 — March 2017 Swap 100,000 MMBtu/month $2.463/MMBtu
January 2017 — March 2017 Swap 300,000 MMBtu/month $2.45/MMBtu
January 2017 — March 2017 Swap 200,000 MMBtu/month $3.287/MMBtu
January 2017 — December 2017 Collar 100,000 MMBtu/month $3.00/MMBtu - $3.65/MMBtu
April 2017 — December 2017 Collar 200,000 MMBtu/month $2.30/MMBtu - $2.60/MMBtu
April 2017 — December 2017 Collar 200,000 MMBtu/month $3.00/MMBtu - $3.44/MMBtu
April 2017 — December 2017 Collar 200,000 MMBtu/month $3.00/MMBtu - $3.50/MMBtu
January 2018 — December 2018 Swap 200,000 MMBtu/month $3.085/MMBtu
January 2018 — December 2018 Swap 250,000 MMBtu/month $3.084/MMBtu
NGLs (C2 - Ethane)
February 2017 — December 2017 Swap 1,050 Bbls/day $11.34/Bbl
NGLs (C3 - Propane)
February 2017 — December 2017 Swap 750 Bbls/day $27.916/Bbl
NGLs (IC4 - Isobutane)
February 2017 — December 2017 Swap 75 Bbls/day $36.7325/Bbl
NGLs (NC4 - Butane)
February 2017 — December 2017 Swap 250 Bbls/day $35.9205/Bbl

Conference Call Information and Summary Presentation

The Company will host a conference call on Friday, March 10, 2017, at 9:00 a.m. Central Time (10:00 a.m. Eastern Time) to discuss fourth quarter and full-year 2016 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:

Dial in: (844) 884-9950 / Conference ID: 70306606
International Dial In: (661) 378-9660
A replay of the call will be available on the Company’s website or by dialing:
Dial in: (855) 859-2056 / Passcode: 70306606

In addition, a fourth quarter and full-year 2016 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 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.

UNAUDITED RESULTS OF OPERATIONS
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2016 2015 2016 2015
Revenues (in thousands):
Oil$14,007 $15,028 $48,311 $82,170
NGLs 5,798 4,370 19,761 20,437
Gas 6,700 6,094 22,230 28,729
Total oil, NGLs and gas sales26,505 25,492 90,302 131,336
Realized gain on commodity derivatives442 14,552 6,132 52,489
Total oil, NGLs and gas sales including derivative impact$26,947 $40,044 $96,434 $183,825
Production:
Oil (MBbls)304 400 1,275 1,882
NGLs (MBbls)380 428 1,529 1,694
Gas (MMcf)2,530 3,011 10,404 11,732
Total (MBoe)1,106 1,330 4,537 5,532
Total (MBoe/d)12.0 14.5 12.4 15.2
Average prices:
Oil (per Bbl)$46.02 $37.60 $37.90 $43.65
NGLs (per Bbl) 15.25 10.20 12.93 12.06
Gas (per Mcf) 2.65 2.02 2.14 2.45
Total (per Boe)$23.96 $19.17 $19.90 $23.74
Realized gain on commodity derivatives (per Boe)0.40 10.94 1.35 9.49
Total including derivative impact (per Boe)$24.36 $30.11 $21.25 $33.23
Costs and expenses (per Boe):
Lease operating$3.40 $5.44 $4.24 $5.24
Production and ad valorem taxes2.43 1.94 1.81 2.00
Exploration0.62 0.17 0.86 0.80
General and administrative(1)6.35 4.10 5.45 5.12
Depletion, depreciation and amortization17.54 17.42 17.42 19.76
(1) Below is a summary of general and administrative expense:
General and administrative – cash Component$4.55 $2.63 $4.07 $3.68
General and administrative – noncash Component1.80 1.47 1.38 1.44


APPROACH RESOURCES INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except shares and per-share amounts)
Three Months Ended Twelve Months Ended
December 31, December 31,
2016 2015 2016 2015
REVENUES:
Oil, NGLs and gas sales $26,505 $ 25,492 $ 90,302 $ 131,336
EXPENSES:
Lease operating 3,766 7,228 19,250 28,972
Production and ad valorem taxes 2,685 2,583 8,217 11,085
Exploration 685 228 3,923 4,439
General and administrative 7,026 5,459 24,734 28,341
Termination costs 1,436
Impairment of oil and gas properties 220,197
Depletion, depreciation and amortization 19,402 23,173 79,044 109,319
Total expenses 33,564 38,671 135,168 403,789
OPERATING LOSS (7,059) (13,179) (44,866) (272,453)
OTHER:
Interest expense, net (7,086) (6,436) (27,259) (25,066)
Gain on debt extinguishment 9,080 10,563
Write-off of debt issuance costs (563)
Realized gain on commodity derivatives 442 14,552 6,132 52,489
Unrealized loss on commodity derivatives (3,343) (10,285) (11,616) (33,214)
Other income 225 1,511 172
LOSS BEFORE INCOME TAX BENEFIT (17,046) (6,043) (76,661) (267,509)
INCOME TAX BENEFIT:
Current (265) (265)
Deferred (3,571) (19) (24,418) (93,140)
NET LOSS $(13,475) $(5,759) $(52,243) $(174,104)
EARNINGS PER SHARE:
Basic $(0.32) $(0.14) $(1.26) $(4.30)
Diluted $(0.32) $(0.14) $(1.26) $(4.30)
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 41,705,462 40,598,098 41,488,206 40,464,283
Diluted 41,705,462 40,598,098 41,488,206 40,464,283


UNAUDITED SELECTED FINANCIAL DATA
Unaudited Consolidated Balance Sheet Data December 31,
(in thousands) 2016 2015
Cash and cash equivalents $21 $600
Other current assets 12,473 19,838
Property and equipment, net, successful efforts method 1,092,061 1,154,546
Total assets $1,104,555 $1,174,984
Current liabilities $26,369 $28,508
Long-term debt (1) 498,349 496,587
Other long-term liabilities 16,885 41,922
Stockholders’ equity 562,952 607,967
Total liabilities and stockholders’ equity $1,104,555 $1,174,984
(1) Long-term debt at December 31, 2016, is comprised of $230.3 million in 7% senior notes due 2021 and $273 million in outstanding borrowings under our senior secured credit facility, net of issuance costs of $5 million. Long-term debt at December 31, 2015, is comprised of $230.3 million in 7% senior notes due 2021 and $273 million in outstanding borrowings under our senior secured credit facility, net of issuance costs of $6.7 million.


Unaudited Consolidated Cash Flow Data Twelve Months Ended December 31,
(in thousands) 2016 2015
Net cash provided (used) by:
Operating activities $26,081 $102,716
Investing activities $(23,890)$(217,347)
Financing activities $(2,770)$114,799

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 under the Financial Reporting subsection of the Investor Relations section of our website at www.approachresources.com.

Adjusted Net Loss

This release contains the non-GAAP financial measures adjusted net loss and adjusted net loss per diluted share, which exclude (1) unrealized loss on commodity derivatives, (2) write-off of debt issuance costs, (3) rig termination fees, (4) impairment of oil and gas properties, (5) termination costs, (6) gain on debt extinguishment, and (7) related income tax effect. The amounts included in the calculation of adjusted net loss and adjusted net loss per diluted share below were computed in accordance with GAAP. We believe adjusted net loss and adjusted net loss 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 to net loss for the three and twelve months ended December 31, 2016 and 2015 (in thousands, except per-share amounts).

Three Months Ended
December 31,
Twelve Months Ended
December 31,
2016 2015 2016 2015
Net loss $(13,475) $(5,759) $(52,243) $(174,104)
Adjustments for certain items:
Unrealized loss on commodity derivatives 3,343 10,285 11,616 33,214
Write-off of debt issuance costs 563
Rig termination fees 2,199
Impairment of oil and gas properties 220,197
Termination costs 1,436
Gain on debt extinguishment (9,080) (10,563)
Related income tax effect (1,170) (422) (4,263) (87,348)
Adjusted net loss $(11,302) $(4,976) $(44,327) $(14,969)
Adjusted net loss per diluted share$(0.27) $(0.12) $(1.07) $(0.37)

EBITDAX

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) impairment of oil and gas properties, (6) termination costs, (7) gain on debt extinguishment, (8) write-off of debt issuance costs, (9) interest expense, net, and (10) 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 table below provides a reconciliation of EBITDAX to net loss for the three and twelve months ended December 31, 2016 and 2015 (in thousands).

Three Months Ended
December 31,
Twelve Months Ended
December 31,
2016 2015 2016 2015
Net loss $(13,475) $(5,759) $(52,243) $(174,104)
Exploration 685 228 3,923 4,439
Depletion, depreciation and amortization 19,402 23,173 79,044 109,319
Share-based compensation 1,998 1,954 6,279 7,954
Unrealized loss on commodity derivatives 3,343 10,285 11,616 33,214
Impairment of oil and gas properties 220,197
Termination costs 1,436
Gain on debt extinguishment (9,080) (10,563)
Write-off of debt issuance costs 563
Interest expense, net 7,086 6,436 27,259 25,066
Income tax benefit (3,571) (284) (24,418) (93,405)
EBITDAX$15,468 $26,953 $52,023 $123,553

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, 2016 and 2015 (in thousands, except per-Boe amounts).

Three Months Ended
December 31,
Twelve Months Ended
December 31,
2016 2015 2016 2015
Operating expenses $33,564 $38,671 $135,168 $403,789
Exploration (685) (228) (3,923) (4,439)
Depletion, depreciation and amortization (19,402) (23,173) (79,044) (109,319)
Share-based compensation (1,998) (1,954) (6,279) (7,954)
Termination costs (1,436)
Impairment of oil and gas properties (220,197)
Cash operating expenses$11,479 $13,316 $45,922 $60,444
Cash operating expenses per Boe$10.38 $10.01 $10.12 $10.93

PV-10

The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $307.9 million at December 31, 2016, and was calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and gas, of $42.69 per Bbl of oil, $14.12 per Bbl of NGLs and $2.47 per MMBtu of natural gas price during 2016, 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.

(in millions) December 31, 2016
PV-10 $307.9
Less income taxes:
Undiscounted future income taxes (132.8)
10% discount factor 122.7
Future discounted income taxes (10.1)
Standardized measure of discounted future net cash flows $297.8

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, 2016 and 2015 (in thousands).

Liquidity at
December 31,
2016 2015
Borrowing base$325,000 $450,000
Cash and cash equivalents 21 600
Senior secured credit facility – outstanding borrowings (273,000) (273,000)
Outstanding letters of credit (575) (325)
Liquidity$51,446 $177,275

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, 2016 and 2015 (in thousands).

Long-Term Debt-to-Capital at
December 31,
2016 2015
Long-term debt (1)$498,349 $496,587
Total stockholders’ equity 562,952 607,967
$1,061,301 $1,104,554
Long-term debt-to-capital 47% 45%
(1) Long-term debt is net of debt issuance costs of $5 million and $6.7
million at December 31, 2016 and December 31, 2015, respectively.


INVESTOR CONTACT Suzanne Ogle Vice President Investor Relations & Corporate Communication ir@approachresources.com 817.989.9000

Source:Approach Resources Inc