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Approach Resources Inc. (NASDAQ: AREX) is an independent oil and gas company headquartered in Fort Worth, Texas. Our operations are focused on exploration, development, production and acquisition of oil and gas properties. We own a leading position in the southern Midland Basin of the greater Permian Basin in West Texas, where we are developing the horizontal Wolfcamp shale oil play.

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Approach Resources Inc. Reports Fourth Quarter and Full-Year 2017 Financial and Operating Results and Provides 2018 Outlook

FORT WORTH, Texas--(BUSINESS WIRE)--Mar. 8, 2018-- Approach Resources Inc. (NASDAQ: AREX) today reported financial and operational results for the fourth quarter and full-year 2017 and estimated year-end 2017 proved reserves.

Fourth Quarter 2017 Highlights

  • Fourth quarter production of 1,064 MBoe or 11.6 MBoe/d
  • Closed bolt-on acquisition increasing our contiguous acreage position by approximately 39,000 net acres and proved developed reserves of 1.6 MMBoe
  • Extended term on revolving credit facility to May 7, 2020, and reaffirmed $325 million borrowing base
  • Net income was $45.8 million, or $0.51 per diluted share. Adjusted net loss (non-GAAP) was $6.1 million, or $0.07 per diluted share
  • EBITDAX (non-GAAP) of $13.9 million
  • Revenues of $28.4 million, an 11% increase over the prior quarter
  • Unhedged cash margin (non-GAAP) of $15.76 per Boe, a 17% increase over the prior quarter

Full-Year 2017 Highlights

  • Full year production of 4,232 MBoe or 11.6 MBoe/d, above the midpoint of annual guidance
  • Year-end 2017 proved reserves 181.5 MMBoe, an increase of 16% over the prior year
  • Type curve updated to 700 MBoe EUR, an increase of 37%
  • Strengthened balance sheet and reduced the outstanding principal of our long-term debt by $127.1 million
  • Increased operating cash flow by $11.4 million or 44% over the prior year
  • 7% decrease in lease operating expense (“LOE”) over the prior year, delivering record low annual LOE of $4.23 per Boe
  • Drilled 13 and completed nine horizontal Wolfcamp wells during the year with an inventory of 10 drilled and uncompleted wells at year-end
  • Reserve replacement ratio of 748%
  • Net loss was $112.4 million, or $1.35 per diluted share. Adjusted net loss (non-GAAP) was $29.8 million, or $0.36 per diluted share
  • EBITDAX (non-GAAP) of $54.8 million, a 5% increase over the prior year

Adjusted net loss, EBITDAX and unhedged cash margin 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 income (loss) and unhedged cash margin to revenues.

Management Comment

Ross Craft, Approach’s Chairman and CEO, commented, “In the face of continued volatile commodity prices, in 2017 we delivered a third consecutive year of fiscal discipline, optimizing returns and providing steady production output. Our continued emphasis on cost control and operating efficiency delivered industry-leading LOE, a record low on a per Boe basis, despite double-digit service cost escalation across the Permian Basin. Even with weather-related operational restrictions during the year, we delivered solid production, above the midpoint of annual guidance. We also successfully completed a strategic exchange and follow-on exchange of senior notes for equity and closed the Pangea West bolt-on acquisition, adding production and HBP acreage in the highest oil concentration of our core position. With 186 horizontal Wolfcamp wells on line at year-end, we continue to demonstrate the resilience of our asset, its suitability for manufacturing-style development and the proficiency of our team as we exploit science and technique to increase well recoveries and manage natural production decline.

“We enter 2018 with our strategic objectives unchanged: deliver a focused, disciplined capital program designed to maximize asset value, maintain our industry-leading cost structure and seek synergistic acquisition opportunities that will strengthen the balance sheet and are accretive to per share metrics. By remaining focused on our plan, we believe we are well positioned to create value for our shareholders.”

Fourth Quarter 2017 Results

Production for fourth quarter 2017 totaled 1,064 MBoe (11.6 MBoe/d), made up of 25% oil, 36% NGLs and 39% natural gas. Average realized commodity prices for fourth quarter 2017, before the effect of commodity derivatives, were $52.09 per Bbl of oil, $22.61 per Bbl of NGLs and $2.32 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $24.01 per Boe for fourth quarter 2017.

Net income for fourth quarter 2017 was $45.8 million, or $0.51 per diluted share, on revenues of $28.4 million. Net income for fourth quarter 2017 included an income tax benefit of $51.9 million related to the reduction in our deferred tax liabilities resulting from the Tax Cuts and Jobs Act and an increase in the fair value of our commodity derivatives of $1.4 million. Excluding these items, adjusted net loss (non-GAAP) for fourth quarter 2017 was $6.1 million, or $0.07 per diluted share. EBITDAX (non-GAAP) for fourth quarter 2017 was $13.9 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net income.

LOE averaged $4.77 per Boe. Production and ad valorem taxes averaged $2.09 per Boe, or 7.8% of oil, NGLs and gas sales. Exploration costs were $0.38 per Boe. Total general and administrative (“G&A”) costs averaged $5.16 per Boe, including cash G&A costs of $4.09 per Boe. Depletion, depreciation and amortization expense averaged $15.20 per Boe. Interest expense totaled $5.4 million.

Full-Year 2017 Results

Production for 2017 was 4,232 MBoe (11.6 MBoe/d), made up of 26% oil, 35% NGLs and 39% natural gas. Average realized commodity prices for 2017, before the effect of commodity derivatives, were $47.63 per Bbl of oil, $18.64 per Bbl of NGLs and $2.53 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $23.86 per Boe for 2017.

Net loss for 2017 was $112.4 million, or $1.35 per diluted share, on revenues of $105.3 million. Net loss for 2017 included a write-off of $139.1 million of deferred tax assets in connection with the completed debt for equity exchange transactions, an income tax benefit of $51.9 million related to the reduction in our deferred tax liabilities resulting from the Tax Cuts and Jobs Act, a gain on debt extinguishment of $5.1 million and an increase in the fair value of our commodity derivative of $4.1 million. Excluding these items, adjusted net loss (non-GAAP) for 2017 was $29.8 million, or $0.36 per diluted share. EBITDAX (non-GAAP) for 2017 was $54.8 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net loss.

LOE averaged an annual record low of $4.23 per Boe. Production and ad valorem taxes averaged $2.04 per Boe, or 8.2% of oil, NGLs and gas sales. Exploration costs were $0.86 per Boe. Total G&A costs averaged $5.75 per Boe, including cash G&A costs of $4.65 per Boe. Depletion, depreciation and amortization expense averaged $16.66 per Boe. Interest expense totaled $21.1 million.

Operations Update

During the fourth quarter of 2017 we drilled one horizontal Wolfcamp well to the A Bench in Pangea West. Currently, the well is in flowback. In total, we completed four wells in the first quarter of 2018 using our Generation X frac design and are very encouraged by the early results of the wells. We hope to have additional information to report in our next operations update.

In 2017, we focused on operating substantially within cash flow and increasing activity in a disciplined manner in conjunction with slowly recovering commodity prices. We maintained focus on managing natural production decline through surface facility optimization, operating efficiencies and investment in well repairs, workovers and maintenance. During 2017, we drilled 13 horizontal Wolfcamp wells. Of these, three wells were drilled to the A bench, five wells were drilled to the B bench and five wells were drilled to the C bench. We completed nine horizontal Wolfcamp wells. Of these, one well was completed in the A bench, five wells were completed in the B bench and three wells were completed in the C bench. The nine completed wells are tracking at or above our 700 MBoe type curve, wells normalized for a 7,500 foot lateral length. At December 31, 2017, we had 10 horizontal wells waiting on completion.

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 sustainable competitive advantages and environmentally responsible facility operations. In 2017, by reducing resource consumption, improving operating practices and minimizing ground transportation we were able to maintain our industry leading LOE per Boe at $4.23.

Innovation Drives Value

Our focus on driving value through a combination of innovation and efficiency is evidenced in our GenX frac design, which balances EUR improvement with cost control. The GenX frac design, first used in 2015, has delivered significant well performance improvement in our horizontal Wolfcamp wells while maintaining a competitive drilling cost. As a result, Approach raised its type curve to an EUR of 700 MBoe to reflect the improved productivity, an increase of 37%.

Fourth Quarter and Full-Year 2017 Production

Fourth quarter 2017 production totaled 1,064 MBoe (11.6 MBoe/d). Full-year 2017 production totaled 4,232 MBoe (11.6 MBoe/d).

    Three and 12 Months Ended
December 31, 2017
Three    
months 12 months
Production:
Oil (MBbls) 270 1,107
NGLs (MBbls) 377 1,486
Gas (MMcf) 2,498 9,829
Total (MBoe) 1,064 4,232
Total (Mboe/d) 11.6 11.6
 
 

2017 Estimated Proved Reserves and Costs Incurred

Year-end 2017 proved reserves totaled 181.5 MMBoe. Year-end 2017 proved reserves were 28% oil, 32% NGLs and 40% natural gas. Proved developed reserves represent approximately 37% of total year-end 2017 proved reserves.

At December 31, 2017, substantially all of our proved reserves were located in our core operating area in the southern Midland Basin. Year-end 2017 estimated proved reserves included 170.2 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, 2017, 2016, and 2015.

    Years Ended December 31,
2017     2016     2015
Horizontal Wolfcamp
Proved developed 55,032 47,861 49,843
Proved undeveloped 115,146   97,502   104,790  
Total 170,178 145,363 154,633
Percent of total proved reserves 94 % 93 % 93 %
 
Other Vertical
Proved developed 11,368 11,014 12,013
Percent of total proved reserves 6 % 7 % 7 %
     
Total proved reserves 181,546   156,377   166,646  
 
 

Extensions and discoveries for 2017 were 33.3 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2017, we acquired 1.6 MMBoe of proved reserves through the bolt-on acquisition, and we reclassified 17.7 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 9.4 MMBoe resulting from updated well performance and technical parameters, and an increase of 3.1 MMBoe due to higher commodity prices.

The following table summarizes the changes in our estimated proved reserves during 2017.

    Oil     NGLs     Natural Gas     Total
(MBbls) (MBbls) (MMcf) (MBoe)
Balance — December 31, 2016 50,031 47,634 352,277 156,377
Extensions and discoveries 10,546 9,975 76,709 33,307
Acquisition of minerals in place 710 394 2,808 1,572
Production(1) (1,107 ) (1,486 ) (11,148 ) (4,452 )
Revisions to previous estimates (10,120 ) 1,431   20,582   (5,259 )
Balance — December 31, 2017 50,060   57,948   441,228   181,545  
 
Reserve replacement ratio
Extensions and discoveries / Production 748 %
 

(1) Production includes 1,319 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, 2017, was $460.8 million. The PV-10 (non-GAAP), or pre-tax present value of our proved reserves discounted at 10%, of our proved reserves at December 31, 2017, was $521 million ($582.2 million at December 31, 2017, NYMEX strip).

The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2017 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 $51.34 per Bbl of oil, $18.67 per Bbl of NGLs and $2.99 per MMBtu of natural gas during 2017.

At NYMEX strip pricing at December 31, 2017, PV-10 is $582.2 million. The following table summarizes the NYMEX strip prices at December 31, 2017.

    2018     2019     2020     2021     2022(1)
Oil (per Bbl) $ 59.55 $ 56.19 $ 53.76 $ 52.29 $ 51.67
Natural gas (per MMBtu) $ 2.84 $ 2.81 $ 2.82 $ 2.85 $ 2.89
 
(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.
 
 

Capital Expenditures

Fourth quarter capital expenditures were $1.3 million. Net capital expenditures incurred during 2017 totaled $47.1 million and were attributable to drilling and development ($44.2 million), infrastructure projects and equipment ($3.6 million) and acreage extensions ($0.2 million), partially offset by a sales tax refund of $0.9 million.

Liquidity Update

At December 31, 2017, we had a $1 billion senior secured revolving credit facility in place with a borrowing base of $325 million, and liquidity of $33.7 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our definition and calculation of liquidity.

Commodity Derivatives Update

We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. At present, approximately 52% of 2018 forecasted oil, 55% of 2018 forecasted natural gas and 50% of NGL production is hedged. The table below is a summary of our current derivatives positions.

    Contract        
Commodity and Period Type Volume Transacted Contract Price
Crude Oil
January 2018 — December 2018 Swap 300 Bbls/day $50.00/Bbl
January 2018 — March 2018 Collar 1,000 Bbls/day $50.00/Bbl - $55.05/Bbl
January 2018 — June 2018 Collar 500 Bbls/day $55.00/Bbl - $60.00/Bbl
January 2018 — September 2018 Swap 700 Bbls/day $60.50/Bbl
April 2018 — September 2018 Swap 800 Bbls/day $60.50/Bbl
 
Natural Gas
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 2018 — December 2018 Swap 1,000 Bbls/day $11.424/Bbl
NGLs (C3 - Propane)
January 2018 — March 2018 Swap 450 Bbls/day $30.24/Bbl
February 2018 — December 2018 Swap 600 Bbls/day $32.991/Bbl
NGLs (IC4 - Isobutane)
January 2018 — March 2018 Swap 50 Bbls/day $36.12/Bbl
February 2018 — December 2018 Swap 50 Bbls/day $38.262/Bbl
NGLs (NC4 - Butane)
January 2018 — March 2018 Swap 150 Bbls/day $35.70/Bbl
February 2018 — December 2018 Swap 200 Bbls/day $38.22/Bbl
NGLs (C5 - Pentane)
January 2018 — December 2018 Swap 200 Bbls/day $56.364/Bbl
 
 

Guidance

The Company’s capital budget for 2018 is a range of $50 million to $70 million, depending on commodity prices. The table below sets forth our production and operating costs and expenses guidance for 2018.

    2018 Guidance
Capital Expenditures (in millions) $50 − $70
 
Production:
Oil (MBbls) 1,150 − 1,250
NGLs (MBbls) 1,450 − 1,550
Gas (MMcf) 9,600 − 10,200
Total (MBoe) 4,200 − 4,500
 
Cash operating costs (per Boe):
Lease operating $4.50 − 5.50
Production and ad valorem taxes 8.25% of oil and gas revenues
Cash general and administrative $4.50 − 5.50
Non-cash operating costs (per Boe):
Non-cash general and administrative $0.50 − 1.00
Exploration $0.50 − 1.00
Depletion, depreciation and amortization $16.00 − 17.00
 
 

First quarter 2018 production is estimated to be approximately 11.3 MBoe/d. First quarter 2018 production will be affected by no new well completions in the fourth quarter of 2017 and weather.

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 2018 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.

Conference Call Information and Summary Presentation

The Company will host a conference call on Friday, March 9, 2018, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss fourth quarter and full-year 2017 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: 4883409
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: 4883409

In addition, a fourth quarter and full-year 2017 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     Twelve Months Ended
December 31, December 31,
2017     2016 2017     2016
Revenues (in thousands):
Oil $ 14,082 $ 14,007 $ 52,748 $ 48,311
NGLs 8,530 5,798 27,702 19,761
Gas   5,805     6,700   24,899     22,230
Total oil, NGLs and gas sales 28,417 26,505 105,349 90,302
Net cash (payment) receipt on derivative settlements   (2,878 )   442   (4,359 )   6,132

Total oil, NGLs and gas sales including derivative impact

$ 25,539   $ 26,947 $ 100,990   $ 96,434
Production:
Oil (MBbls) 270 304 1,107 1,275
NGLs (MBbls) 377 380 1,486 1,529
Gas (MMcf)   2,498     2,530   9,829     10,404
Total (MBoe) 1,064 1,106 4,232 4,537
Total (MBoe/d) 11.6 12.0 11.6 12.4
Average prices:
Oil (per Bbl) $ 52.09 $ 46.02 $ 47.63 $ 37.90
NGLs (per Bbl) 22.61 15.25 18.64 12.93
Gas (per Mcf)   2.32     2.65   2.53     2.14
Total (per Boe) $ 26.71 $ 23.96 $ 24.89 $ 19.90
Net cash (payment) receipt on derivative settlements (per Boe)   (2.70 )   0.40   (1.03 )   1.35
Total including derivative impact (per Boe) $ 24.01 $ 24.36 $ 23.86 $ 21.25
Costs and expenses (per Boe):
Lease operating $ 4.77 $ 3.40 $ 4.23 $ 4.24
Production and ad valorem taxes 2.09 2.43 2.04 1.81
Exploration 0.38 0.62 0.86 0.86
General and administrative (1) 5.16 6.35 5.75 5.45
Depletion, depreciation and amortization 15.20 17.54 16.66 17.42
(1) Below is a summary of general and administrative expense:
General and administrative - cash component $ 4.09 $ 4.55 $ 4.65 $ 4.07
General and administrative - noncash component (share-based compensation) 1.07 1.80 1.10 1.38
 
 
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,
  2017         2016     2017         2016  
REVENUES:
Oil, NGLs and gas sales $ 28,417 $ 26,505 $ 105,349 $ 90,302
EXPENSES:
Lease operating 5,076 3,766 17,902 19,250
Production and ad valorem taxes 2,219 2,685 8,644 8,217
Exploration 406 685 3,657 3,923
General and administrative 5,491 7,026 24,333 24,734
Depletion, depreciation and amortization   16,173     19,402     70,521     79,044  
Total expenses   29,365     33,564     125,057     135,168  
OPERATING LOSS (948 ) (7,059 ) (19,708 ) (44,866 )
OTHER:
Interest expense, net (5,370 ) (7,086 ) (21,053 ) (27,259 )
Gain on debt extinguishment 5,053
Write-off of debt issuance costs (563 )
Commodity derivative (loss) gain (1,377 ) (2,901 ) (262 ) (5,484 )
Other income           32     1,511  

LOSS BEFORE INCOME TAX (BENEFIT) PROVISION

(7,695 ) (17,046 ) (35,938 ) (76,661 )

INCOME TAX (BENEFIT) PROVISION:

Current (66 )
Deferred   (53,512 )   (3,571 )   76,487     (24,418 )
NET INCOME (LOSS) $ 45,817   $ (13,475 ) $ (112,359 ) $ (52,243 )
EARNINGS (LOSS) PER SHARE:
Basic $ 0.51   $ (0.32 ) $ (1.35 ) $ (1.26 )
Diluted $ 0.51   $ (0.32 ) $ (1.35 ) $ (1.26 )
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 90,114,659 41,705,462 83,404,104 41,488,206
Diluted 90,114,659 41,705,462 83,404,104 41,488,206
 
 

UNAUDITED SELECTED FINANCIAL DATA

 
Unaudited Consolidated Balance Sheet Data     December 31,
(in thousands) 2017     2016
Cash and cash equivalents $ 21 $ 21
Other current assets 16,679 12,473
Property and equipment, net, successful efforts method   1,082,876   1,092,061
Total assets $ 1,099,576 $ 1,104,555
 
Current liabilities $ 25,067 $ 26,369
Long-term debt (1) 373,460 498,349
Deferred income taxes 82,102 5,615
Other long-term liabilities 11,531 11,270
Stockholders' equity   607,416   562,952
Total liabilities and stockholders' equity $ 1,099,576 $ 1,104,555
 
(1) Long-term debt at December 31, 2017, is comprised of $85.2 million in 7% senior notes due 2021 and $291 million in outstanding borrowings under our revolving credit facility, net of issuance costs of $1.1 million and $1.7 million, respectively. 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 revolving credit facility, net of issuance costs of $3.7 million and $1.3 million, respectively.
   
 
Unaudited Consolidated Cash Flow Data Year Ended December 31,
(in thousands)   2017         2016  
Net cash provided by (used in):
Operating activities $ 37,454 $ 26,081
Investing activities (52,409 ) (23,890 )
Financing activities 14,955 (2,770 )
 
 

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 excludes (1) non-cash fair value (gain) loss on commodity derivatives, (2) gain on debt extinguishment, (3) write-off of debt issuance costs, (4) write-off of deferred tax assets, (5) acquisition related costs, (6) tax benefit related to federal tax law change, and (6) related income tax effect on adjustments and other discrete tax items. 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 income (loss) for the three and twelve months ended December 31, 2017 and 2016 (in thousands, except per-share amounts).

       
Three Months Ended Twelve Months Ended
December 31, December 31,
  2017         2016     2017         2016  
Net income (loss) $ 45,817 $ (13,475 ) $ (112,359 ) $ (52,243 )
Adjustments for certain items:
Non-cash fair value (gain) loss on derivatives (1,500 ) 3,343 (4,097 ) 11,616
Gain on debt extinguishment (5,053 )
Write-off of debt issuance costs 563
Write-off of deferred tax assets 139,090
Acquisition related costs 110 110
Tax benefit related to change in federal tax law (51,939 ) (51,939 )
Tax effect and other discrete tax items (1)   1,446     401     4,443     (2,437 )
 
Adjusted net loss $ (6,066 ) $ (9,731 ) $ (29,805 ) $ (42,501 )
Adjusted net loss per diluted share $ (0.07 ) $ (0.23 ) $ (0.36 ) $ (1.02 )

 

(1) The estimated income tax impacts on adjustments to net income (loss) are computed based upon a statutory rate of 35%, applicable to all periods presented. Additionally, this includes the tax impact of a tax shortfall related to share-based compensation of $1 million, and $1.6 million for the three months ended December 31, 2017, and December 31, 2016, respectively; and $1.3 million and $1.8 million for the years ended December 31, 2017, and December 31, 2016, respectively.
 
 

EBITDAX

We define EBITDAX as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) non-cash fair value (gain) loss on derivatives, (5) gain on debt extinguishment, (6) write-off of debt issuance costs, (7) interest expense, net, and (8) 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 income (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 income (loss) for the three and twelve months ended December 31, 2017 and 2016 (in thousands).

    Three Months Ended     Twelve Months Ended
December 31, December 31,
  2017         2016     2017         2016  
Net income (loss) $ 45,817 $ (13,475 ) $ (112,359 ) $ (52,243 )
Exploration 406 685 3,657 3,923
Depletion, depreciation and amortization 16,173 19,402 70,521 79,044
Share-based compensation 1,138 1,998 4,656 6,279
Non-cash fair value (gain) loss on derivatives (1,500 ) 3,343 (4,097 ) 11,616
Gain on debt extinguishment (5,053 )
Write-off of debt issuance costs 563
Interest expense, net 5,370 7,086 21,053 27,259
Income tax (benefit) provision   (53,512 )   (3,571 )   76,421     (24,418 )
 
EBITDAX $ 13,892   $ 15,468   $ 54,799   $ 52,023  
 
 

Unhedged Cash Margin and Cash Operating Expenses

We define unhedged cash margin as revenue, less 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. Unhedged cash margin and cash operating expenses are not measures of operating income or cash flows as determined by GAAP. The amounts included in the calculations of unhedged cash margin and cash operating expenses were computed in accordance with GAAP. Unhedged cash margin and cash operating expenses are presented herein and reconciled to the GAAP measures of revenue and operating expenses. We use unhedged cash margin and cash operating expenses as an indicator of the Company’s profitability and ability to manage its operating income 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 unhedged cash margin and cash operating expenses to revenues and operating expenses for the three and twelve months ended December 31, 2017 and 2016 (in thousands, except per-Boe amounts).

    Three Months Ended     Twelve Months Ended
December 31, December 31,
  2017         2016     2017         2016  
Revenues $ 28,417 $ 26,505 $ 105,349 $ 90,302
Production (Mboe) 1,064 1,106 4,232 4,537
Average realized price (per Boe) $ 26.71 $ 23.96 $ 24.89 $ 19.90
 
Operating expenses $ 29,365 $ 33,564 $ 125,057 $ 135,168
Exploration (406 ) (685 ) (3,657 ) (3,923 )
Depletion, depreciation and amortization (16,173 ) (19,402 ) (70,521 ) (79,044 )
Share-based compensation   (1,138 )   (1,998 )   (4,656 )   (6,279 )
Cash operating expenses $ 11,648 $ 11,479 $ 46,223 $ 45,922
Cash operating expenses per Boe $ 10.95   $ 10.38   $ 10.92   $ 10.12  
 
Unhedged cash margin $ 16,769 $ 15,026 $ 59,126 $ 44,380
Unhedged cash margin per Boe $ 15.76   $ 13.58   $ 13.97   $ 9.78  
 
 

PV-10

The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $521 million at December 31, 2017, and was calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and gas, of $51.34 per Bbl of oil, $18.67 per Bbl of NGLs and $2.99 per MMBtu of natural gas price during 2017, 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, 2017
PV-10 $ 521.0
Less income taxes:
Undiscounted future income taxes (323.3 )
10% discount factor   263.3  
Future discounted income taxes   (60.0 )
 
Standardized measure of discounted future net cash flows $ 461.0  
 
 

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, 2017 and 2016 (in thousands).

    Year Ended December 31,
  2017         2016  
Credit Facility commitments $ 325,000 $ 325,000
Cash and cash equivalents 21 21
Long-term debt — Credit Facility (291,000 ) (273,000 )
Undrawn letters of credit   (325 )   (575 )
Liquidity $ 33,696   $ 51,446  
 
 

Source: Approach Resources Inc.

Approach Resources Inc.
Suzanne Ogle, 817-989-9000
Vice President – Investor Relations & Corporate Communications
ir@approachresources.com

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Approach Resources Inc. Reports Fourth Quarter and Full-Year 2017 Financial and Operating Results and Provides 2018 Outlook

FORT WORTH, Texas--(BUSINESS WIRE)--Mar. 8, 2018-- Approach Resources Inc. (NASDAQ: AREX) today reported financial and operational results for the fourth quarter and full-year 2017 and estimated year-end 2017 proved reserves.

Fourth Quarter 2017 Highlights

  • Fourth quarter production of 1,064 MBoe or 11.6 MBoe/d
  • Closed bolt-on acquisition increasing our contiguous acreage position by approximately 39,000 net acres and proved developed reserves of 1.6 MMBoe
  • Extended term on revolving credit facility to May 7, 2020, and reaffirmed $325 million borrowing base
  • Net income was $45.8 million, or $0.51 per diluted share. Adjusted net loss (non-GAAP) was $6.1 million, or $0.07 per diluted share
  • EBITDAX (non-GAAP) of $13.9 million
  • Revenues of $28.4 million, an 11% increase over the prior quarter
  • Unhedged cash margin (non-GAAP) of $15.76 per Boe, a 17% increase over the prior quarter

Full-Year 2017 Highlights

  • Full year production of 4,232 MBoe or 11.6 MBoe/d, above the midpoint of annual guidance
  • Year-end 2017 proved reserves 181.5 MMBoe, an increase of 16% over the prior year
  • Type curve updated to 700 MBoe EUR, an increase of 37%
  • Strengthened balance sheet and reduced the outstanding principal of our long-term debt by $127.1 million
  • Increased operating cash flow by $11.4 million or 44% over the prior year
  • 7% decrease in lease operating expense (“LOE”) over the prior year, delivering record low annual LOE of $4.23 per Boe
  • Drilled 13 and completed nine horizontal Wolfcamp wells during the year with an inventory of 10 drilled and uncompleted wells at year-end
  • Reserve replacement ratio of 748%
  • Net loss was $112.4 million, or $1.35 per diluted share. Adjusted net loss (non-GAAP) was $29.8 million, or $0.36 per diluted share
  • EBITDAX (non-GAAP) of $54.8 million, a 5% increase over the prior year

Adjusted net loss, EBITDAX and unhedged cash margin 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 income (loss) and unhedged cash margin to revenues.

Management Comment

Ross Craft, Approach’s Chairman and CEO, commented, “In the face of continued volatile commodity prices, in 2017 we delivered a third consecutive year of fiscal discipline, optimizing returns and providing steady production output. Our continued emphasis on cost control and operating efficiency delivered industry-leading LOE, a record low on a per Boe basis, despite double-digit service cost escalation across the Permian Basin. Even with weather-related operational restrictions during the year, we delivered solid production, above the midpoint of annual guidance. We also successfully completed a strategic exchange and follow-on exchange of senior notes for equity and closed the Pangea West bolt-on acquisition, adding production and HBP acreage in the highest oil concentration of our core position. With 186 horizontal Wolfcamp wells on line at year-end, we continue to demonstrate the resilience of our asset, its suitability for manufacturing-style development and the proficiency of our team as we exploit science and technique to increase well recoveries and manage natural production decline.

“We enter 2018 with our strategic objectives unchanged: deliver a focused, disciplined capital program designed to maximize asset value, maintain our industry-leading cost structure and seek synergistic acquisition opportunities that will strengthen the balance sheet and are accretive to per share metrics. By remaining focused on our plan, we believe we are well positioned to create value for our shareholders.”

Fourth Quarter 2017 Results

Production for fourth quarter 2017 totaled 1,064 MBoe (11.6 MBoe/d), made up of 25% oil, 36% NGLs and 39% natural gas. Average realized commodity prices for fourth quarter 2017, before the effect of commodity derivatives, were $52.09 per Bbl of oil, $22.61 per Bbl of NGLs and $2.32 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $24.01 per Boe for fourth quarter 2017.

Net income for fourth quarter 2017 was $45.8 million, or $0.51 per diluted share, on revenues of $28.4 million. Net income for fourth quarter 2017 included an income tax benefit of $51.9 million related to the reduction in our deferred tax liabilities resulting from the Tax Cuts and Jobs Act and an increase in the fair value of our commodity derivatives of $1.4 million. Excluding these items, adjusted net loss (non-GAAP) for fourth quarter 2017 was $6.1 million, or $0.07 per diluted share. EBITDAX (non-GAAP) for fourth quarter 2017 was $13.9 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net income.

LOE averaged $4.77 per Boe. Production and ad valorem taxes averaged $2.09 per Boe, or 7.8% of oil, NGLs and gas sales. Exploration costs were $0.38 per Boe. Total general and administrative (“G&A”) costs averaged $5.16 per Boe, including cash G&A costs of $4.09 per Boe. Depletion, depreciation and amortization expense averaged $15.20 per Boe. Interest expense totaled $5.4 million.

Full-Year 2017 Results

Production for 2017 was 4,232 MBoe (11.6 MBoe/d), made up of 26% oil, 35% NGLs and 39% natural gas. Average realized commodity prices for 2017, before the effect of commodity derivatives, were $47.63 per Bbl of oil, $18.64 per Bbl of NGLs and $2.53 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $23.86 per Boe for 2017.

Net loss for 2017 was $112.4 million, or $1.35 per diluted share, on revenues of $105.3 million. Net loss for 2017 included a write-off of $139.1 million of deferred tax assets in connection with the completed debt for equity exchange transactions, an income tax benefit of $51.9 million related to the reduction in our deferred tax liabilities resulting from the Tax Cuts and Jobs Act, a gain on debt extinguishment of $5.1 million and an increase in the fair value of our commodity derivative of $4.1 million. Excluding these items, adjusted net loss (non-GAAP) for 2017 was $29.8 million, or $0.36 per diluted share. EBITDAX (non-GAAP) for 2017 was $54.8 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net loss.

LOE averaged an annual record low of $4.23 per Boe. Production and ad valorem taxes averaged $2.04 per Boe, or 8.2% of oil, NGLs and gas sales. Exploration costs were $0.86 per Boe. Total G&A costs averaged $5.75 per Boe, including cash G&A costs of $4.65 per Boe. Depletion, depreciation and amortization expense averaged $16.66 per Boe. Interest expense totaled $21.1 million.

Operations Update

During the fourth quarter of 2017 we drilled one horizontal Wolfcamp well to the A Bench in Pangea West. Currently, the well is in flowback. In total, we completed four wells in the first quarter of 2018 using our Generation X frac design and are very encouraged by the early results of the wells. We hope to have additional information to report in our next operations update.

In 2017, we focused on operating substantially within cash flow and increasing activity in a disciplined manner in conjunction with slowly recovering commodity prices. We maintained focus on managing natural production decline through surface facility optimization, operating efficiencies and investment in well repairs, workovers and maintenance. During 2017, we drilled 13 horizontal Wolfcamp wells. Of these, three wells were drilled to the A bench, five wells were drilled to the B bench and five wells were drilled to the C bench. We completed nine horizontal Wolfcamp wells. Of these, one well was completed in the A bench, five wells were completed in the B bench and three wells were completed in the C bench. The nine completed wells are tracking at or above our 700 MBoe type curve, wells normalized for a 7,500 foot lateral length. At December 31, 2017, we had 10 horizontal wells waiting on completion.

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 sustainable competitive advantages and environmentally responsible facility operations. In 2017, by reducing resource consumption, improving operating practices and minimizing ground transportation we were able to maintain our industry leading LOE per Boe at $4.23.

Innovation Drives Value

Our focus on driving value through a combination of innovation and efficiency is evidenced in our GenX frac design, which balances EUR improvement with cost control. The GenX frac design, first used in 2015, has delivered significant well performance improvement in our horizontal Wolfcamp wells while maintaining a competitive drilling cost. As a result, Approach raised its type curve to an EUR of 700 MBoe to reflect the improved productivity, an increase of 37%.

Fourth Quarter and Full-Year 2017 Production

Fourth quarter 2017 production totaled 1,064 MBoe (11.6 MBoe/d). Full-year 2017 production totaled 4,232 MBoe (11.6 MBoe/d).

    Three and 12 Months Ended
December 31, 2017
Three    
months 12 months
Production:
Oil (MBbls) 270 1,107
NGLs (MBbls) 377 1,486
Gas (MMcf) 2,498 9,829
Total (MBoe) 1,064 4,232
Total (Mboe/d) 11.6 11.6
 
 

2017 Estimated Proved Reserves and Costs Incurred

Year-end 2017 proved reserves totaled 181.5 MMBoe. Year-end 2017 proved reserves were 28% oil, 32% NGLs and 40% natural gas. Proved developed reserves represent approximately 37% of total year-end 2017 proved reserves.

At December 31, 2017, substantially all of our proved reserves were located in our core operating area in the southern Midland Basin. Year-end 2017 estimated proved reserves included 170.2 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, 2017, 2016, and 2015.

    Years Ended December 31,
2017     2016     2015
Horizontal Wolfcamp
Proved developed 55,032 47,861 49,843
Proved undeveloped 115,146   97,502   104,790  
Total 170,178 145,363 154,633
Percent of total proved reserves 94 % 93 % 93 %
 
Other Vertical
Proved developed 11,368 11,014 12,013
Percent of total proved reserves 6 % 7 % 7 %
     
Total proved reserves 181,546   156,377   166,646  
 
 

Extensions and discoveries for 2017 were 33.3 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2017, we acquired 1.6 MMBoe of proved reserves through the bolt-on acquisition, and we reclassified 17.7 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 9.4 MMBoe resulting from updated well performance and technical parameters, and an increase of 3.1 MMBoe due to higher commodity prices.

The following table summarizes the changes in our estimated proved reserves during 2017.

    Oil     NGLs     Natural Gas     Total
(MBbls) (MBbls) (MMcf) (MBoe)
Balance — December 31, 2016 50,031 47,634 352,277 156,377
Extensions and discoveries 10,546 9,975 76,709 33,307
Acquisition of minerals in place 710 394 2,808 1,572
Production(1) (1,107 ) (1,486 ) (11,148 ) (4,452 )
Revisions to previous estimates (10,120 ) 1,431   20,582   (5,259 )
Balance — December 31, 2017 50,060   57,948   441,228   181,545  
 
Reserve replacement ratio
Extensions and discoveries / Production 748 %
 

(1) Production includes 1,319 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, 2017, was $460.8 million. The PV-10 (non-GAAP), or pre-tax present value of our proved reserves discounted at 10%, of our proved reserves at December 31, 2017, was $521 million ($582.2 million at December 31, 2017, NYMEX strip).

The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2017 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 $51.34 per Bbl of oil, $18.67 per Bbl of NGLs and $2.99 per MMBtu of natural gas during 2017.

At NYMEX strip pricing at December 31, 2017, PV-10 is $582.2 million. The following table summarizes the NYMEX strip prices at December 31, 2017.

    2018     2019     2020     2021     2022(1)
Oil (per Bbl) $ 59.55 $ 56.19 $ 53.76 $ 52.29 $ 51.67
Natural gas (per MMBtu) $ 2.84 $ 2.81 $ 2.82 $ 2.85 $ 2.89
 
(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.
 
 

Capital Expenditures

Fourth quarter capital expenditures were $1.3 million. Net capital expenditures incurred during 2017 totaled $47.1 million and were attributable to drilling and development ($44.2 million), infrastructure projects and equipment ($3.6 million) and acreage extensions ($0.2 million), partially offset by a sales tax refund of $0.9 million.

Liquidity Update

At December 31, 2017, we had a $1 billion senior secured revolving credit facility in place with a borrowing base of $325 million, and liquidity of $33.7 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our definition and calculation of liquidity.

Commodity Derivatives Update

We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. At present, approximately 52% of 2018 forecasted oil, 55% of 2018 forecasted natural gas and 50% of NGL production is hedged. The table below is a summary of our current derivatives positions.

    Contract        
Commodity and Period Type Volume Transacted Contract Price
Crude Oil
January 2018 — December 2018 Swap 300 Bbls/day $50.00/Bbl
January 2018 — March 2018 Collar 1,000 Bbls/day $50.00/Bbl - $55.05/Bbl
January 2018 — June 2018 Collar 500 Bbls/day $55.00/Bbl - $60.00/Bbl
January 2018 — September 2018 Swap 700 Bbls/day $60.50/Bbl
April 2018 — September 2018 Swap 800 Bbls/day $60.50/Bbl
 
Natural Gas
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 2018 — December 2018 Swap 1,000 Bbls/day $11.424/Bbl
NGLs (C3 - Propane)
January 2018 — March 2018 Swap 450 Bbls/day $30.24/Bbl
February 2018 — December 2018 Swap 600 Bbls/day $32.991/Bbl
NGLs (IC4 - Isobutane)
January 2018 — March 2018 Swap 50 Bbls/day $36.12/Bbl
February 2018 — December 2018 Swap 50 Bbls/day $38.262/Bbl
NGLs (NC4 - Butane)
January 2018 — March 2018 Swap 150 Bbls/day $35.70/Bbl
February 2018 — December 2018 Swap 200 Bbls/day $38.22/Bbl
NGLs (C5 - Pentane)
January 2018 — December 2018 Swap 200 Bbls/day $56.364/Bbl
 
 

Guidance

The Company’s capital budget for 2018 is a range of $50 million to $70 million, depending on commodity prices. The table below sets forth our production and operating costs and expenses guidance for 2018.

    2018 Guidance
Capital Expenditures (in millions) $50 − $70
 
Production:
Oil (MBbls) 1,150 − 1,250
NGLs (MBbls) 1,450 − 1,550
Gas (MMcf) 9,600 − 10,200
Total (MBoe) 4,200 − 4,500
 
Cash operating costs (per Boe):
Lease operating $4.50 − 5.50
Production and ad valorem taxes 8.25% of oil and gas revenues
Cash general and administrative $4.50 − 5.50
Non-cash operating costs (per Boe):
Non-cash general and administrative $0.50 − 1.00
Exploration $0.50 − 1.00
Depletion, depreciation and amortization $16.00 − 17.00
 
 

First quarter 2018 production is estimated to be approximately 11.3 MBoe/d. First quarter 2018 production will be affected by no new well completions in the fourth quarter of 2017 and weather.

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 2018 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.

Conference Call Information and Summary Presentation

The Company will host a conference call on Friday, March 9, 2018, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss fourth quarter and full-year 2017 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: 4883409
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: 4883409

In addition, a fourth quarter and full-year 2017 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     Twelve Months Ended
December 31, December 31,
2017     2016 2017     2016
Revenues (in thousands):
Oil $ 14,082 $ 14,007 $ 52,748 $ 48,311
NGLs 8,530 5,798 27,702 19,761
Gas   5,805     6,700   24,899     22,230
Total oil, NGLs and gas sales 28,417 26,505 105,349 90,302
Net cash (payment) receipt on derivative settlements   (2,878 )   442   (4,359 )   6,132

Total oil, NGLs and gas sales including derivative impact

$ 25,539   $ 26,947 $ 100,990   $ 96,434
Production:
Oil (MBbls) 270 304 1,107 1,275
NGLs (MBbls) 377 380 1,486 1,529
Gas (MMcf)   2,498     2,530   9,829     10,404
Total (MBoe) 1,064 1,106 4,232 4,537
Total (MBoe/d) 11.6 12.0 11.6 12.4
Average prices:
Oil (per Bbl) $ 52.09 $ 46.02 $ 47.63 $ 37.90
NGLs (per Bbl) 22.61 15.25 18.64 12.93
Gas (per Mcf)   2.32     2.65   2.53     2.14
Total (per Boe) $ 26.71 $ 23.96 $ 24.89 $ 19.90
Net cash (payment) receipt on derivative settlements (per Boe)   (2.70 )   0.40   (1.03 )   1.35
Total including derivative impact (per Boe) $ 24.01 $ 24.36 $ 23.86 $ 21.25
Costs and expenses (per Boe):
Lease operating $ 4.77 $ 3.40 $ 4.23 $ 4.24
Production and ad valorem taxes 2.09 2.43 2.04 1.81
Exploration 0.38 0.62 0.86 0.86
General and administrative (1) 5.16 6.35 5.75 5.45
Depletion, depreciation and amortization 15.20 17.54 16.66 17.42
(1) Below is a summary of general and administrative expense:
General and administrative - cash component $ 4.09 $ 4.55 $ 4.65 $ 4.07
General and administrative - noncash component (share-based compensation) 1.07 1.80 1.10 1.38
 
 
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,
  2017         2016     2017         2016  
REVENUES:
Oil, NGLs and gas sales $ 28,417 $ 26,505 $ 105,349 $ 90,302
EXPENSES:
Lease operating 5,076 3,766 17,902 19,250
Production and ad valorem taxes 2,219 2,685 8,644 8,217
Exploration 406 685 3,657 3,923
General and administrative 5,491 7,026 24,333 24,734
Depletion, depreciation and amortization   16,173     19,402     70,521     79,044  
Total expenses   29,365     33,564     125,057     135,168  
OPERATING LOSS (948 ) (7,059 ) (19,708 ) (44,866 )
OTHER:
Interest expense, net (5,370 ) (7,086 ) (21,053 ) (27,259 )
Gain on debt extinguishment 5,053
Write-off of debt issuance costs (563 )
Commodity derivative (loss) gain (1,377 ) (2,901 ) (262 ) (5,484 )
Other income           32     1,511  

LOSS BEFORE INCOME TAX (BENEFIT) PROVISION

(7,695 ) (17,046 ) (35,938 ) (76,661 )

INCOME TAX (BENEFIT) PROVISION:

Current (66 )
Deferred   (53,512 )   (3,571 )   76,487     (24,418 )
NET INCOME (LOSS) $ 45,817   $ (13,475 ) $ (112,359 ) $ (52,243 )
EARNINGS (LOSS) PER SHARE:
Basic $ 0.51   $ (0.32 ) $ (1.35 ) $ (1.26 )
Diluted $ 0.51   $ (0.32 ) $ (1.35 ) $ (1.26 )
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 90,114,659 41,705,462 83,404,104 41,488,206
Diluted 90,114,659 41,705,462 83,404,104 41,488,206
 
 

UNAUDITED SELECTED FINANCIAL DATA

 
Unaudited Consolidated Balance Sheet Data     December 31,
(in thousands) 2017     2016
Cash and cash equivalents $ 21 $ 21
Other current assets 16,679 12,473
Property and equipment, net, successful efforts method   1,082,876   1,092,061
Total assets $ 1,099,576 $ 1,104,555
 
Current liabilities $ 25,067 $ 26,369
Long-term debt (1) 373,460 498,349
Deferred income taxes 82,102 5,615
Other long-term liabilities 11,531 11,270
Stockholders' equity   607,416   562,952
Total liabilities and stockholders' equity $ 1,099,576 $ 1,104,555
 
(1) Long-term debt at December 31, 2017, is comprised of $85.2 million in 7% senior notes due 2021 and $291 million in outstanding borrowings under our revolving credit facility, net of issuance costs of $1.1 million and $1.7 million, respectively. 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 revolving credit facility, net of issuance costs of $3.7 million and $1.3 million, respectively.
   
 
Unaudited Consolidated Cash Flow Data Year Ended December 31,
(in thousands)   2017         2016  
Net cash provided by (used in):
Operating activities $ 37,454 $ 26,081
Investing activities (52,409 ) (23,890 )
Financing activities 14,955 (2,770 )
 
 

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 excludes (1) non-cash fair value (gain) loss on commodity derivatives, (2) gain on debt extinguishment, (3) write-off of debt issuance costs, (4) write-off of deferred tax assets, (5) acquisition related costs, (6) tax benefit related to federal tax law change, and (6) related income tax effect on adjustments and other discrete tax items. 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 income (loss) for the three and twelve months ended December 31, 2017 and 2016 (in thousands, except per-share amounts).

       
Three Months Ended Twelve Months Ended
December 31, December 31,
  2017         2016     2017         2016  
Net income (loss) $ 45,817 $ (13,475 ) $ (112,359 ) $ (52,243 )
Adjustments for certain items:
Non-cash fair value (gain) loss on derivatives (1,500 ) 3,343 (4,097 ) 11,616
Gain on debt extinguishment (5,053 )
Write-off of debt issuance costs 563
Write-off of deferred tax assets 139,090
Acquisition related costs 110 110
Tax benefit related to change in federal tax law (51,939 ) (51,939 )
Tax effect and other discrete tax items (1)   1,446     401     4,443     (2,437 )
 
Adjusted net loss $ (6,066 ) $ (9,731 ) $ (29,805 ) $ (42,501 )
Adjusted net loss per diluted share $ (0.07 ) $ (0.23 ) $ (0.36 ) $ (1.02 )

 

(1) The estimated income tax impacts on adjustments to net income (loss) are computed based upon a statutory rate of 35%, applicable to all periods presented. Additionally, this includes the tax impact of a tax shortfall related to share-based compensation of $1 million, and $1.6 million for the three months ended December 31, 2017, and December 31, 2016, respectively; and $1.3 million and $1.8 million for the years ended December 31, 2017, and December 31, 2016, respectively.
 
 

EBITDAX

We define EBITDAX as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) non-cash fair value (gain) loss on derivatives, (5) gain on debt extinguishment, (6) write-off of debt issuance costs, (7) interest expense, net, and (8) 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 income (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 income (loss) for the three and twelve months ended December 31, 2017 and 2016 (in thousands).

    Three Months Ended     Twelve Months Ended
December 31, December 31,
  2017         2016     2017         2016  
Net income (loss) $ 45,817 $ (13,475 ) $ (112,359 ) $ (52,243 )
Exploration 406 685 3,657 3,923
Depletion, depreciation and amortization 16,173 19,402 70,521 79,044
Share-based compensation 1,138 1,998 4,656 6,279
Non-cash fair value (gain) loss on derivatives (1,500 ) 3,343 (4,097 ) 11,616
Gain on debt extinguishment (5,053 )
Write-off of debt issuance costs 563
Interest expense, net 5,370 7,086 21,053 27,259
Income tax (benefit) provision   (53,512 )   (3,571 )   76,421     (24,418 )
 
EBITDAX $ 13,892   $ 15,468   $ 54,799   $ 52,023  
 
 

Unhedged Cash Margin and Cash Operating Expenses

We define unhedged cash margin as revenue, less 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. Unhedged cash margin and cash operating expenses are not measures of operating income or cash flows as determined by GAAP. The amounts included in the calculations of unhedged cash margin and cash operating expenses were computed in accordance with GAAP. Unhedged cash margin and cash operating expenses are presented herein and reconciled to the GAAP measures of revenue and operating expenses. We use unhedged cash margin and cash operating expenses as an indicator of the Company’s profitability and ability to manage its operating income 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 unhedged cash margin and cash operating expenses to revenues and operating expenses for the three and twelve months ended December 31, 2017 and 2016 (in thousands, except per-Boe amounts).

    Three Months Ended     Twelve Months Ended
December 31, December 31,
  2017         2016     2017         2016  
Revenues $ 28,417 $ 26,505 $ 105,349 $ 90,302
Production (Mboe) 1,064 1,106 4,232 4,537
Average realized price (per Boe) $ 26.71 $ 23.96 $ 24.89 $ 19.90
 
Operating expenses $ 29,365 $ 33,564 $ 125,057 $ 135,168
Exploration (406 ) (685 ) (3,657 ) (3,923 )
Depletion, depreciation and amortization (16,173 ) (19,402 ) (70,521 ) (79,044 )
Share-based compensation   (1,138 )   (1,998 )   (4,656 )   (6,279 )
Cash operating expenses $ 11,648 $ 11,479 $ 46,223 $ 45,922
Cash operating expenses per Boe $ 10.95   $ 10.38   $ 10.92   $ 10.12  
 
Unhedged cash margin $ 16,769 $ 15,026 $ 59,126 $ 44,380
Unhedged cash margin per Boe $ 15.76   $ 13.58   $ 13.97   $ 9.78  
 
 

PV-10

The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $521 million at December 31, 2017, and was calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and gas, of $51.34 per Bbl of oil, $18.67 per Bbl of NGLs and $2.99 per MMBtu of natural gas price during 2017, 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, 2017
PV-10 $ 521.0
Less income taxes:
Undiscounted future income taxes (323.3 )
10% discount factor   263.3  
Future discounted income taxes   (60.0 )
 
Standardized measure of discounted future net cash flows $ 461.0  
 
 

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, 2017 and 2016 (in thousands).

    Year Ended December 31,
  2017         2016  
Credit Facility commitments $ 325,000 $ 325,000
Cash and cash equivalents 21 21
Long-term debt — Credit Facility (291,000 ) (273,000 )
Undrawn letters of credit   (325 )   (575 )
Liquidity $ 33,696   $ 51,446  
 
 

Source: Approach Resources Inc.

Approach Resources Inc.
Suzanne Ogle, 817-989-9000
Vice President – Investor Relations & Corporate Communications
ir@approachresources.com

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Approach Resources Inc. Reports Fourth Quarter and Full-Year 2017 Financial and Operating Results and Provides 2018 Outlook

FORT WORTH, Texas--(BUSINESS WIRE)--Mar. 8, 2018-- Approach Resources Inc. (NASDAQ: AREX) today reported financial and operational results for the fourth quarter and full-year 2017 and estimated year-end 2017 proved reserves.

Fourth Quarter 2017 Highlights

  • Fourth quarter production of 1,064 MBoe or 11.6 MBoe/d
  • Closed bolt-on acquisition increasing our contiguous acreage position by approximately 39,000 net acres and proved developed reserves of 1.6 MMBoe
  • Extended term on revolving credit facility to May 7, 2020, and reaffirmed $325 million borrowing base
  • Net income was $45.8 million, or $0.51 per diluted share. Adjusted net loss (non-GAAP) was $6.1 million, or $0.07 per diluted share
  • EBITDAX (non-GAAP) of $13.9 million
  • Revenues of $28.4 million, an 11% increase over the prior quarter
  • Unhedged cash margin (non-GAAP) of $15.76 per Boe, a 17% increase over the prior quarter

Full-Year 2017 Highlights

  • Full year production of 4,232 MBoe or 11.6 MBoe/d, above the midpoint of annual guidance
  • Year-end 2017 proved reserves 181.5 MMBoe, an increase of 16% over the prior year
  • Type curve updated to 700 MBoe EUR, an increase of 37%
  • Strengthened balance sheet and reduced the outstanding principal of our long-term debt by $127.1 million
  • Increased operating cash flow by $11.4 million or 44% over the prior year
  • 7% decrease in lease operating expense (“LOE”) over the prior year, delivering record low annual LOE of $4.23 per Boe
  • Drilled 13 and completed nine horizontal Wolfcamp wells during the year with an inventory of 10 drilled and uncompleted wells at year-end
  • Reserve replacement ratio of 748%
  • Net loss was $112.4 million, or $1.35 per diluted share. Adjusted net loss (non-GAAP) was $29.8 million, or $0.36 per diluted share
  • EBITDAX (non-GAAP) of $54.8 million, a 5% increase over the prior year

Adjusted net loss, EBITDAX and unhedged cash margin 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 income (loss) and unhedged cash margin to revenues.

Management Comment

Ross Craft, Approach’s Chairman and CEO, commented, “In the face of continued volatile commodity prices, in 2017 we delivered a third consecutive year of fiscal discipline, optimizing returns and providing steady production output. Our continued emphasis on cost control and operating efficiency delivered industry-leading LOE, a record low on a per Boe basis, despite double-digit service cost escalation across the Permian Basin. Even with weather-related operational restrictions during the year, we delivered solid production, above the midpoint of annual guidance. We also successfully completed a strategic exchange and follow-on exchange of senior notes for equity and closed the Pangea West bolt-on acquisition, adding production and HBP acreage in the highest oil concentration of our core position. With 186 horizontal Wolfcamp wells on line at year-end, we continue to demonstrate the resilience of our asset, its suitability for manufacturing-style development and the proficiency of our team as we exploit science and technique to increase well recoveries and manage natural production decline.

“We enter 2018 with our strategic objectives unchanged: deliver a focused, disciplined capital program designed to maximize asset value, maintain our industry-leading cost structure and seek synergistic acquisition opportunities that will strengthen the balance sheet and are accretive to per share metrics. By remaining focused on our plan, we believe we are well positioned to create value for our shareholders.”

Fourth Quarter 2017 Results

Production for fourth quarter 2017 totaled 1,064 MBoe (11.6 MBoe/d), made up of 25% oil, 36% NGLs and 39% natural gas. Average realized commodity prices for fourth quarter 2017, before the effect of commodity derivatives, were $52.09 per Bbl of oil, $22.61 per Bbl of NGLs and $2.32 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $24.01 per Boe for fourth quarter 2017.

Net income for fourth quarter 2017 was $45.8 million, or $0.51 per diluted share, on revenues of $28.4 million. Net income for fourth quarter 2017 included an income tax benefit of $51.9 million related to the reduction in our deferred tax liabilities resulting from the Tax Cuts and Jobs Act and an increase in the fair value of our commodity derivatives of $1.4 million. Excluding these items, adjusted net loss (non-GAAP) for fourth quarter 2017 was $6.1 million, or $0.07 per diluted share. EBITDAX (non-GAAP) for fourth quarter 2017 was $13.9 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net income.

LOE averaged $4.77 per Boe. Production and ad valorem taxes averaged $2.09 per Boe, or 7.8% of oil, NGLs and gas sales. Exploration costs were $0.38 per Boe. Total general and administrative (“G&A”) costs averaged $5.16 per Boe, including cash G&A costs of $4.09 per Boe. Depletion, depreciation and amortization expense averaged $15.20 per Boe. Interest expense totaled $5.4 million.

Full-Year 2017 Results

Production for 2017 was 4,232 MBoe (11.6 MBoe/d), made up of 26% oil, 35% NGLs and 39% natural gas. Average realized commodity prices for 2017, before the effect of commodity derivatives, were $47.63 per Bbl of oil, $18.64 per Bbl of NGLs and $2.53 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $23.86 per Boe for 2017.

Net loss for 2017 was $112.4 million, or $1.35 per diluted share, on revenues of $105.3 million. Net loss for 2017 included a write-off of $139.1 million of deferred tax assets in connection with the completed debt for equity exchange transactions, an income tax benefit of $51.9 million related to the reduction in our deferred tax liabilities resulting from the Tax Cuts and Jobs Act, a gain on debt extinguishment of $5.1 million and an increase in the fair value of our commodity derivative of $4.1 million. Excluding these items, adjusted net loss (non-GAAP) for 2017 was $29.8 million, or $0.36 per diluted share. EBITDAX (non-GAAP) for 2017 was $54.8 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net loss.

LOE averaged an annual record low of $4.23 per Boe. Production and ad valorem taxes averaged $2.04 per Boe, or 8.2% of oil, NGLs and gas sales. Exploration costs were $0.86 per Boe. Total G&A costs averaged $5.75 per Boe, including cash G&A costs of $4.65 per Boe. Depletion, depreciation and amortization expense averaged $16.66 per Boe. Interest expense totaled $21.1 million.

Operations Update

During the fourth quarter of 2017 we drilled one horizontal Wolfcamp well to the A Bench in Pangea West. Currently, the well is in flowback. In total, we completed four wells in the first quarter of 2018 using our Generation X frac design and are very encouraged by the early results of the wells. We hope to have additional information to report in our next operations update.

In 2017, we focused on operating substantially within cash flow and increasing activity in a disciplined manner in conjunction with slowly recovering commodity prices. We maintained focus on managing natural production decline through surface facility optimization, operating efficiencies and investment in well repairs, workovers and maintenance. During 2017, we drilled 13 horizontal Wolfcamp wells. Of these, three wells were drilled to the A bench, five wells were drilled to the B bench and five wells were drilled to the C bench. We completed nine horizontal Wolfcamp wells. Of these, one well was completed in the A bench, five wells were completed in the B bench and three wells were completed in the C bench. The nine completed wells are tracking at or above our 700 MBoe type curve, wells normalized for a 7,500 foot lateral length. At December 31, 2017, we had 10 horizontal wells waiting on completion.

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 sustainable competitive advantages and environmentally responsible facility operations. In 2017, by reducing resource consumption, improving operating practices and minimizing ground transportation we were able to maintain our industry leading LOE per Boe at $4.23.

Innovation Drives Value

Our focus on driving value through a combination of innovation and efficiency is evidenced in our GenX frac design, which balances EUR improvement with cost control. The GenX frac design, first used in 2015, has delivered significant well performance improvement in our horizontal Wolfcamp wells while maintaining a competitive drilling cost. As a result, Approach raised its type curve to an EUR of 700 MBoe to reflect the improved productivity, an increase of 37%.

Fourth Quarter and Full-Year 2017 Production

Fourth quarter 2017 production totaled 1,064 MBoe (11.6 MBoe/d). Full-year 2017 production totaled 4,232 MBoe (11.6 MBoe/d).

    Three and 12 Months Ended
December 31, 2017
Three    
months 12 months
Production:
Oil (MBbls) 270 1,107
NGLs (MBbls) 377 1,486
Gas (MMcf) 2,498 9,829
Total (MBoe) 1,064 4,232
Total (Mboe/d) 11.6 11.6
 
 

2017 Estimated Proved Reserves and Costs Incurred

Year-end 2017 proved reserves totaled 181.5 MMBoe. Year-end 2017 proved reserves were 28% oil, 32% NGLs and 40% natural gas. Proved developed reserves represent approximately 37% of total year-end 2017 proved reserves.

At December 31, 2017, substantially all of our proved reserves were located in our core operating area in the southern Midland Basin. Year-end 2017 estimated proved reserves included 170.2 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, 2017, 2016, and 2015.

    Years Ended December 31,
2017     2016     2015
Horizontal Wolfcamp
Proved developed 55,032 47,861 49,843
Proved undeveloped 115,146   97,502   104,790  
Total 170,178 145,363 154,633
Percent of total proved reserves 94 % 93 % 93 %
 
Other Vertical
Proved developed 11,368 11,014 12,013
Percent of total proved reserves 6 % 7 % 7 %
     
Total proved reserves 181,546   156,377   166,646  
 
 

Extensions and discoveries for 2017 were 33.3 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2017, we acquired 1.6 MMBoe of proved reserves through the bolt-on acquisition, and we reclassified 17.7 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 9.4 MMBoe resulting from updated well performance and technical parameters, and an increase of 3.1 MMBoe due to higher commodity prices.

The following table summarizes the changes in our estimated proved reserves during 2017.

    Oil     NGLs     Natural Gas     Total
(MBbls) (MBbls) (MMcf) (MBoe)
Balance — December 31, 2016 50,031 47,634 352,277 156,377
Extensions and discoveries 10,546 9,975 76,709 33,307
Acquisition of minerals in place 710 394 2,808 1,572
Production(1) (1,107 ) (1,486 ) (11,148 ) (4,452 )
Revisions to previous estimates (10,120 ) 1,431   20,582   (5,259 )
Balance — December 31, 2017 50,060   57,948   441,228   181,545  
 
Reserve replacement ratio
Extensions and discoveries / Production 748 %
 

(1) Production includes 1,319 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, 2017, was $460.8 million. The PV-10 (non-GAAP), or pre-tax present value of our proved reserves discounted at 10%, of our proved reserves at December 31, 2017, was $521 million ($582.2 million at December 31, 2017, NYMEX strip).

The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2017 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 $51.34 per Bbl of oil, $18.67 per Bbl of NGLs and $2.99 per MMBtu of natural gas during 2017.

At NYMEX strip pricing at December 31, 2017, PV-10 is $582.2 million. The following table summarizes the NYMEX strip prices at December 31, 2017.

    2018     2019     2020     2021     2022(1)
Oil (per Bbl) $ 59.55 $ 56.19 $ 53.76 $ 52.29 $ 51.67
Natural gas (per MMBtu) $ 2.84 $ 2.81 $ 2.82 $ 2.85 $ 2.89
 
(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.
 
 

Capital Expenditures

Fourth quarter capital expenditures were $1.3 million. Net capital expenditures incurred during 2017 totaled $47.1 million and were attributable to drilling and development ($44.2 million), infrastructure projects and equipment ($3.6 million) and acreage extensions ($0.2 million), partially offset by a sales tax refund of $0.9 million.

Liquidity Update

At December 31, 2017, we had a $1 billion senior secured revolving credit facility in place with a borrowing base of $325 million, and liquidity of $33.7 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our definition and calculation of liquidity.

Commodity Derivatives Update

We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. At present, approximately 52% of 2018 forecasted oil, 55% of 2018 forecasted natural gas and 50% of NGL production is hedged. The table below is a summary of our current derivatives positions.

    Contract        
Commodity and Period Type Volume Transacted Contract Price
Crude Oil
January 2018 — December 2018 Swap 300 Bbls/day $50.00/Bbl
January 2018 — March 2018 Collar 1,000 Bbls/day $50.00/Bbl - $55.05/Bbl
January 2018 — June 2018 Collar 500 Bbls/day $55.00/Bbl - $60.00/Bbl
January 2018 — September 2018 Swap 700 Bbls/day $60.50/Bbl
April 2018 — September 2018 Swap 800 Bbls/day $60.50/Bbl
 
Natural Gas
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 2018 — December 2018 Swap 1,000 Bbls/day $11.424/Bbl
NGLs (C3 - Propane)
January 2018 — March 2018 Swap 450 Bbls/day $30.24/Bbl
February 2018 — December 2018 Swap 600 Bbls/day $32.991/Bbl
NGLs (IC4 - Isobutane)
January 2018 — March 2018 Swap 50 Bbls/day $36.12/Bbl
February 2018 — December 2018 Swap 50 Bbls/day $38.262/Bbl
NGLs (NC4 - Butane)
January 2018 — March 2018 Swap 150 Bbls/day $35.70/Bbl
February 2018 — December 2018 Swap 200 Bbls/day $38.22/Bbl
NGLs (C5 - Pentane)
January 2018 — December 2018 Swap 200 Bbls/day $56.364/Bbl
 
 

Guidance

The Company’s capital budget for 2018 is a range of $50 million to $70 million, depending on commodity prices. The table below sets forth our production and operating costs and expenses guidance for 2018.

    2018 Guidance
Capital Expenditures (in millions) $50 − $70
 
Production:
Oil (MBbls) 1,150 − 1,250
NGLs (MBbls) 1,450 − 1,550
Gas (MMcf) 9,600 − 10,200
Total (MBoe) 4,200 − 4,500
 
Cash operating costs (per Boe):
Lease operating $4.50 − 5.50
Production and ad valorem taxes 8.25% of oil and gas revenues
Cash general and administrative $4.50 − 5.50
Non-cash operating costs (per Boe):
Non-cash general and administrative $0.50 − 1.00
Exploration $0.50 − 1.00
Depletion, depreciation and amortization $16.00 − 17.00
 
 

First quarter 2018 production is estimated to be approximately 11.3 MBoe/d. First quarter 2018 production will be affected by no new well completions in the fourth quarter of 2017 and weather.

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 2018 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.

Conference Call Information and Summary Presentation

The Company will host a conference call on Friday, March 9, 2018, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss fourth quarter and full-year 2017 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: 4883409
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: 4883409

In addition, a fourth quarter and full-year 2017 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     Twelve Months Ended
December 31, December 31,
2017     2016 2017     2016
Revenues (in thousands):
Oil $ 14,082 $ 14,007 $ 52,748 $ 48,311
NGLs 8,530 5,798 27,702 19,761
Gas   5,805     6,700   24,899     22,230
Total oil, NGLs and gas sales 28,417 26,505 105,349 90,302
Net cash (payment) receipt on derivative settlements   (2,878 )   442   (4,359 )   6,132

Total oil, NGLs and gas sales including derivative impact

$ 25,539   $ 26,947 $ 100,990   $ 96,434
Production:
Oil (MBbls) 270 304 1,107 1,275
NGLs (MBbls) 377 380 1,486 1,529
Gas (MMcf)   2,498     2,530   9,829     10,404
Total (MBoe) 1,064 1,106 4,232 4,537
Total (MBoe/d) 11.6 12.0 11.6 12.4
Average prices:
Oil (per Bbl) $ 52.09 $ 46.02 $ 47.63 $ 37.90
NGLs (per Bbl) 22.61 15.25 18.64 12.93
Gas (per Mcf)   2.32     2.65   2.53     2.14
Total (per Boe) $ 26.71 $ 23.96 $ 24.89 $ 19.90
Net cash (payment) receipt on derivative settlements (per Boe)   (2.70 )   0.40   (1.03 )   1.35
Total including derivative impact (per Boe) $ 24.01 $ 24.36 $ 23.86 $ 21.25
Costs and expenses (per Boe):
Lease operating $ 4.77 $ 3.40 $ 4.23 $ 4.24
Production and ad valorem taxes 2.09 2.43 2.04 1.81
Exploration 0.38 0.62 0.86 0.86
General and administrative (1) 5.16 6.35 5.75 5.45
Depletion, depreciation and amortization 15.20 17.54 16.66 17.42
(1) Below is a summary of general and administrative expense:
General and administrative - cash component $ 4.09 $ 4.55 $ 4.65 $ 4.07
General and administrative - noncash component (share-based compensation) 1.07 1.80 1.10 1.38
 
 
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,
  2017         2016     2017         2016  
REVENUES:
Oil, NGLs and gas sales $ 28,417 $ 26,505 $ 105,349 $ 90,302
EXPENSES:
Lease operating 5,076 3,766 17,902 19,250
Production and ad valorem taxes 2,219 2,685 8,644 8,217
Exploration 406 685 3,657 3,923
General and administrative 5,491 7,026 24,333 24,734
Depletion, depreciation and amortization   16,173     19,402     70,521     79,044  
Total expenses   29,365     33,564     125,057     135,168  
OPERATING LOSS (948 ) (7,059 ) (19,708 ) (44,866 )
OTHER:
Interest expense, net (5,370 ) (7,086 ) (21,053 ) (27,259 )
Gain on debt extinguishment 5,053
Write-off of debt issuance costs (563 )
Commodity derivative (loss) gain (1,377 ) (2,901 ) (262 ) (5,484 )
Other income           32     1,511  

LOSS BEFORE INCOME TAX (BENEFIT) PROVISION

(7,695 ) (17,046 ) (35,938 ) (76,661 )

INCOME TAX (BENEFIT) PROVISION:

Current (66 )
Deferred   (53,512 )   (3,571 )   76,487     (24,418 )
NET INCOME (LOSS) $ 45,817   $ (13,475 ) $ (112,359 ) $ (52,243 )
EARNINGS (LOSS) PER SHARE:
Basic $ 0.51   $ (0.32 ) $ (1.35 ) $ (1.26 )
Diluted $ 0.51   $ (0.32 ) $ (1.35 ) $ (1.26 )
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 90,114,659 41,705,462 83,404,104 41,488,206
Diluted 90,114,659 41,705,462 83,404,104 41,488,206
 
 

UNAUDITED SELECTED FINANCIAL DATA

 
Unaudited Consolidated Balance Sheet Data     December 31,
(in thousands) 2017     2016
Cash and cash equivalents $ 21 $ 21
Other current assets 16,679 12,473
Property and equipment, net, successful efforts method   1,082,876   1,092,061
Total assets $ 1,099,576 $ 1,104,555
 
Current liabilities $ 25,067 $ 26,369
Long-term debt (1) 373,460 498,349
Deferred income taxes 82,102 5,615
Other long-term liabilities 11,531 11,270
Stockholders' equity   607,416   562,952
Total liabilities and stockholders' equity $ 1,099,576 $ 1,104,555
 
(1) Long-term debt at December 31, 2017, is comprised of $85.2 million in 7% senior notes due 2021 and $291 million in outstanding borrowings under our revolving credit facility, net of issuance costs of $1.1 million and $1.7 million, respectively. 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 revolving credit facility, net of issuance costs of $3.7 million and $1.3 million, respectively.
   
 
Unaudited Consolidated Cash Flow Data Year Ended December 31,
(in thousands)   2017         2016  
Net cash provided by (used in):
Operating activities $ 37,454 $ 26,081
Investing activities (52,409 ) (23,890 )
Financing activities 14,955 (2,770 )
 
 

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 excludes (1) non-cash fair value (gain) loss on commodity derivatives, (2) gain on debt extinguishment, (3) write-off of debt issuance costs, (4) write-off of deferred tax assets, (5) acquisition related costs, (6) tax benefit related to federal tax law change, and (6) related income tax effect on adjustments and other discrete tax items. 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 income (loss) for the three and twelve months ended December 31, 2017 and 2016 (in thousands, except per-share amounts).

       
Three Months Ended Twelve Months Ended
December 31, December 31,
  2017         2016     2017         2016  
Net income (loss) $ 45,817 $ (13,475 ) $ (112,359 ) $ (52,243 )
Adjustments for certain items:
Non-cash fair value (gain) loss on derivatives (1,500 ) 3,343 (4,097 ) 11,616
Gain on debt extinguishment (5,053 )
Write-off of debt issuance costs 563
Write-off of deferred tax assets 139,090
Acquisition related costs 110 110
Tax benefit related to change in federal tax law (51,939 ) (51,939 )
Tax effect and other discrete tax items (1)   1,446     401     4,443     (2,437 )
 
Adjusted net loss $ (6,066 ) $ (9,731 ) $ (29,805 ) $ (42,501 )
Adjusted net loss per diluted share $ (0.07 ) $ (0.23 ) $ (0.36 ) $ (1.02 )

 

(1) The estimated income tax impacts on adjustments to net income (loss) are computed based upon a statutory rate of 35%, applicable to all periods presented. Additionally, this includes the tax impact of a tax shortfall related to share-based compensation of $1 million, and $1.6 million for the three months ended December 31, 2017, and December 31, 2016, respectively; and $1.3 million and $1.8 million for the years ended December 31, 2017, and December 31, 2016, respectively.
 
 

EBITDAX

We define EBITDAX as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) non-cash fair value (gain) loss on derivatives, (5) gain on debt extinguishment, (6) write-off of debt issuance costs, (7) interest expense, net, and (8) 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 income (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 income (loss) for the three and twelve months ended December 31, 2017 and 2016 (in thousands).

    Three Months Ended     Twelve Months Ended
December 31, December 31,
  2017         2016     2017         2016  
Net income (loss) $ 45,817 $ (13,475 ) $ (112,359 ) $ (52,243 )
Exploration 406 685 3,657 3,923
Depletion, depreciation and amortization 16,173 19,402 70,521 79,044
Share-based compensation 1,138 1,998 4,656 6,279
Non-cash fair value (gain) loss on derivatives (1,500 ) 3,343 (4,097 ) 11,616
Gain on debt extinguishment (5,053 )
Write-off of debt issuance costs 563
Interest expense, net 5,370 7,086 21,053 27,259
Income tax (benefit) provision   (53,512 )   (3,571 )   76,421     (24,418 )
 
EBITDAX $ 13,892   $ 15,468   $ 54,799   $ 52,023  
 
 

Unhedged Cash Margin and Cash Operating Expenses

We define unhedged cash margin as revenue, less 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. Unhedged cash margin and cash operating expenses are not measures of operating income or cash flows as determined by GAAP. The amounts included in the calculations of unhedged cash margin and cash operating expenses were computed in accordance with GAAP. Unhedged cash margin and cash operating expenses are presented herein and reconciled to the GAAP measures of revenue and operating expenses. We use unhedged cash margin and cash operating expenses as an indicator of the Company’s profitability and ability to manage its operating income 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 unhedged cash margin and cash operating expenses to revenues and operating expenses for the three and twelve months ended December 31, 2017 and 2016 (in thousands, except per-Boe amounts).

    Three Months Ended     Twelve Months Ended
December 31, December 31,
  2017         2016     2017         2016  
Revenues $ 28,417 $ 26,505 $ 105,349 $ 90,302
Production (Mboe) 1,064 1,106 4,232 4,537
Average realized price (per Boe) $ 26.71 $ 23.96 $ 24.89 $ 19.90
 
Operating expenses $ 29,365 $ 33,564 $ 125,057 $ 135,168
Exploration (406 ) (685 ) (3,657 ) (3,923 )
Depletion, depreciation and amortization (16,173 ) (19,402 ) (70,521 ) (79,044 )
Share-based compensation   (1,138 )   (1,998 )   (4,656 )   (6,279 )
Cash operating expenses $ 11,648 $ 11,479 $ 46,223 $ 45,922
Cash operating expenses per Boe $ 10.95   $ 10.38   $ 10.92   $ 10.12  
 
Unhedged cash margin $ 16,769 $ 15,026 $ 59,126 $ 44,380
Unhedged cash margin per Boe $ 15.76   $ 13.58   $ 13.97   $ 9.78  
 
 

PV-10

The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $521 million at December 31, 2017, and was calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and gas, of $51.34 per Bbl of oil, $18.67 per Bbl of NGLs and $2.99 per MMBtu of natural gas price during 2017, 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, 2017
PV-10 $ 521.0
Less income taxes:
Undiscounted future income taxes (323.3 )
10% discount factor   263.3  
Future discounted income taxes   (60.0 )
 
Standardized measure of discounted future net cash flows $ 461.0  
 
 

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, 2017 and 2016 (in thousands).

    Year Ended December 31,
  2017         2016  
Credit Facility commitments $ 325,000 $ 325,000
Cash and cash equivalents 21 21
Long-term debt — Credit Facility (291,000 ) (273,000 )
Undrawn letters of credit   (325 )   (575 )
Liquidity $ 33,696   $ 51,446  
 
 

Source: Approach Resources Inc.

Approach Resources Inc.
Suzanne Ogle, 817-989-9000
Vice President – Investor Relations & Corporate Communications
ir@approachresources.com

IR Contacts

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Sergei Krylov

Executive Vice President & Chief Financial Officer

ir@approachresources.com

Tel: 817.989.9000

Suzanne Ogle

Vice President – Investor
Relations & Corporate Communications

sogle@approachresources.com

Tel: 817.989.9000

 
 
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Contact Us
  • Approach Resources Inc.
    One Ridgmar Centre
    6500 West Freeway, Ste 800
    Fort Worth, Texas 76116USA
  • Workp 1 (817) 989-9000
  • Faxf 1 (817) 989-9001