Approach Resources Inc. Reports Fourth Quarter and Full-year 2018 Financial and Operating Results

Source Press Release
Company Approach Resources Inc 
Tags Unconventional Resources, Strategy - Upstream, Capital Spending, Guidance, Strategy - Corporate, Financial & Operating Data
Date March 18, 2019

Approach Resources Inc. (NASDAQ: AREX) today reported financial and operational results for the fourth quarter and full-year 2018, estimated year-end 2018 proved reserves and provided an update on its efforts to pursue deleveraging alternatives.

Fourth Quarter 2018 Highlights

  • Fourth quarter production of 963 MBoe or 10.5 MBoe/d
  • Net income was $0.9 million, or $0.01 per diluted share. Adjusted net loss (non-GAAP) was $6.9 million, or $0.07 per diluted share
  • EBITDAX (non-GAAP) of $13.5 million
  • Cash operating expenses (non-GAAP) of $8.85 per Boe, a 28% decrease over the prior quarter

Full-Year 2018 Highlights

  • Full year production of 4,082 MBoe or 11.2 MBoe/d
  • Year-end 2018 proved reserves 180.1 MMBoe, an increase in oil reserves of 5% over the prior year
  • Drilled six and completed nine horizontal Wolfcamp wells during the year with an inventory of seven drilled and uncompleted wells at year-end
  • Net loss was $19.9 million, or $0.21 per diluted share. Adjusted net loss (non-GAAP) was $25 million, or $0.26 per diluted share
  • EBITDAX (non-GAAP) of $59 million, a 7% increase over the prior year
  • Revenue of $114 million, an 8% increase over the prior year
  • Unhedged cash margin (non-GAAP) of $16.19 per Boe, a 16% increase over the prior year

Adjusted net loss, EBITDAX, cash operating expenses 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, “Due in part to the sharp decline in commodity prices and extreme WAHA gas discount in the basin in the fourth quarter, we focused on conserving capital and reducing our cash operating expenses during the quarter. Additionally, we continued to evaluate alternatives to reduce our leverage. In 2019, we will continue to focus on alternatives to strengthen our balance sheet and manage our covenants under our credit facility. Our capital expenditure budget is designed to be funded primarily through cash flows from operations. As a result of the current commodity price environment, as well as our focus on addressing our leverage, we do not expect any significant drilling and completion activity in the first quarter of 2019.”

Company Continues to Explore Deleveraging Alternatives

In order to improve our leverage position to meet upcoming financial covenants under the revolving credit facility, we have been, and currently are, pursuing or considering a number of deleveraging and strategic actions, which in certain cases may require the consent of current lenders, stockholders or bond holders. If we do not accomplish one or more of the deleveraging transactions discussed below, we do not believe we will be able to comply with the total leverage ratio covenant in our revolving credit facility beginning with the measurement date of March 31, 2019.

On April 12, 2018, our largest shareholder, Wilks Brothers, LLC, and its affiliate SDW Investments, LLC (collectively, “Wilks”), disclosed on Schedule 13D/A that they intended to engage in discussions with the Company regarding their investment in the Company, including the possible acquisition of additional shares of common stock through the exchange of approximately $60 million of 7% Senior Notes due 2021 (the “Senior Notes”) currently held by Wilks (the “Exchange Transaction”). In April 2018, our board of directors formed a committee of independent directors (the “Committee”) to evaluate a potential Exchange Transaction as well as other strategic alternatives (the “Competing Transactions”). The Committee hired financial and legal advisors to advise the Committee on these matters. The Committee engaged in discussions with Wilks regarding an Exchange Transaction in 2018, but in mid-2018 the Wilks and the Committee deferred further discussions regarding a stand-alone Exchange Transaction pending resolution of the Company’s discussions regarding the potential transaction described in the following paragraph.

In addition, management has reviewed numerous cash flow producing properties for potential acquisition over the last several years in order to grow our production base and reduce our leverage ratio to a sustainable level and one that is in compliance with our financial covenants. In early 2018, we retained a financial advisor, separate from the Committee’s advisor, and began discussions with a potential seller and multiple financing counterparties for the purchase of a set of substantial cash flow producing properties. Despite a deteriorating commodity price market, discussions with both the seller and financing parties progressed throughout 2018. However, no definitive agreements ultimately were executed, and the negotiations currently are not active.

In March 2019, our board of directors expanded the scope of the Committee to explore, in addition to an Exchange Transaction, other financing alternatives and deleveraging transactions, including without limitation (i) amendments or waivers to the covenants or other provisions of our revolving credit facility, (ii) raising new capital in private or public markets and (iii) restructuring our balance sheet either in court or through an out of court agreement with creditors. We are also considering operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and intend to continue to pursue and consider other strategic alternatives, including: (i) acquiring assets with existing production and cash flows by issuing preferred and common equity to finance such acquisitions; (ii) selling existing producing or midstream assets; (iii) merging with a strategic partner. The Committee has re-commenced discussions with the Wilks regarding an Exchange Transaction and intends to continue those discussions as part of its review of financing alternatives and deleveraging transactions. We currently are in discussions with our CEO regarding his separation from the Company. We expect to engage in discussions with our President and Chief Administrative Officer regarding their continued employment or potential separation. The Company is evaluating plans for succession. There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our credit facility covenants.

If an event of default under our credit facility occurred, our lenders could accelerate the maturity of the outstanding indebtedness, making it immediately due and payable, and we would not have sufficient liquidity to repay those amounts. However, we believe we have adequate liquidity for current, near-term working capital needs from cash generated from operations and, to the extent available, unused borrowing capacity under our revolving credit facility, each assuming (i) no reduction in our borrowing base from our semi-annual borrowing base redetermination and (ii) no acceleration of amounts due under our revolving credit facility.

Fourth Quarter 2018 Results

Production for fourth quarter 2018 totaled 963 MBoe (10.5 MBoe/d), made up of 26% oil, 35% NGLs and 39% natural gas. Average realized commodity prices for fourth quarter 2018, before the effect of commodity derivatives, were $55.23 per Bbl of oil, $19.91 per Bbl of NGLs and $0.79 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $22.86 per Boe for fourth quarter 2018.

Net income for fourth quarter 2018 was $0.9 million, or $0.01 per diluted share, on revenues of $22.4 million. Excluding the increase in the fair value of our commodity derivatives of $10.1 million, adjusted net loss (non-GAAP) for fourth quarter 2018 was $6.9 million, or $0.07 per diluted share. EBITDAX (non-GAAP) for fourth quarter 2018 was $13.5 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net income.

Lease operating expense (“LOE”) averaged $5.21 per Boe. Production and ad valorem taxes averaged $1.80 per Boe, or 7.7% of oil, NGLs and gas sales. Exploration costs were $0.43 per Boe. Total general and administrative (“G&A”) costs averaged $2.80 per Boe, including cash G&A costs of $1.84 per Boe. Depletion, depreciation and amortization expense averaged $14.96 per Boe. Interest expense totaled $6.6 million.

Full-Year 2018 Results

Production for 2018 was 4,082 MBoe (11.2 MBoe/d), made up of 26% oil, 36% NGLs and 38% natural gas. Average realized commodity prices for 2018, before the effect of commodity derivatives, were $62.04 per Bbl of oil, $23.28 per Bbl of NGLs and $1.49 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $26.21 per Boe for 2018.

Net loss for 2018 was $19.9 million, or $0.21 per diluted share, on revenues of $114 million. Excluding the increase in fair value of our commodity derivatives of $6.7 million, adjusted net loss (non-GAAP) for 2018 was $25 million, or $0.26 per diluted share. EBITDAX (non-GAAP) for 2018 was $59 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net loss.

LOE averaged $5.18 per Boe. Production and ad valorem taxes averaged $2.19 per Boe, or 7.8% of oil, NGLs and gas sales. Exploration costs were $0.10 per Boe. Total G&A costs averaged $5.13 per Boe, including cash G&A costs of $4.38 per Boe. Depletion, depreciation and amortization expense averaged $15.05 per Boe. Interest expense totaled $25.1 million.

Operations Update

In light of continued commodity price deterioration and the extreme WAHA gas discount in the basin, we deferred third and fourth quarter 2018 drilling and completion activities, and incurred capital expenditures of $0.2 million in the fourth quarter.

In 2018, we focused on executing a disciplined capital budget and managing natural production decline through surface facility optimization, operating efficiencies and investment in well repairs, workovers and maintenance. During 2018, we drilled six and completed nine horizontal Wolfcamp wells. Of these, three wells were completed in the A bench, three wells were completed in the B bench and three wells were completed in the C bench. At December 31, 2018, we had seven 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 continues to provide sustainable competitive advantages and environmentally responsible facility operations. In 2018, we maintained an industry leading average drilling and completion cost of $4.6 million per horizontal well and LOE per Boe of $5.18.

Fourth Quarter and Full-Year 2018 Production

Fourth quarter 2018 production totaled 963 MBoe (10.5 MBoe/d). Full-year 2018 production totaled 4,082 MBoe (11.2 MBoe/d).

      Three and 12 Months Ended 
      December 31, 2018 
      Three months      12 months 
Production:             
Oil (MBbls)      251      1,070 
NGLs (MBbls)      338      1,443 
Gas (MMcf)      2,240      9,408 
Total (MBoe)      963      4,082 
Total (Mboe/d)      10.5      11.2 
             

2018 Estimated Proved Reserves and Costs Incurred

Year-end 2018 proved reserves totaled 180.1 MMBoe. Year-end 2018 proved reserves were 29% oil, 31% NGLs and 40% natural gas. Proved developed reserves represent approximately 37% of total year-end 2018 proved reserves.

At December 31, 2018, substantially all of our proved reserves were located in our core operating area in the southern Midland Basin. Year-end 2018 estimated proved reserves included 168.2 MMBoe attributable to the horizontal Wolfcamp shale play.

Extensions and discoveries for 2018 were 35 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2018, we reclassified 33.1 MMBoe of proved undeveloped reserves to unproved reserves. The reclassified reserves 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 0.2 MMBoe resulting from updated well performance and technical parameters, and an increase of 1.9 MMBoe due to higher commodity prices, partially offset by a decrease of 1.4 MMBoe due to an increase in operating expenses and natural gas price differentials.

The following table summarizes the changes in our estimated proved reserves during 2018.

      Oil      NGLs      Natural Gas      Total 
      (MBbls)      (MBbls)      (MMcf)      (MBoe) 
Balance — December 31, 2017      50,060        57,948        441,228        181,545   
Extensions and discoveries      14,572        8,819        69,362        34,951   
Production(1)      (1,070      (1,443      (10,793      (4,312 
Revisions to previous estimates      (11,104      (8,788      (73,359      (32,117 
Balance — December 31, 2018      52,458        56,536        426,438        180,067   

(1) Production includes 1,385 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, 2018, was $660 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, 2018, was $761.8 million.

The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2018 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 $65.68 per Bbl of oil, $24.12 per Bbl of NGLs and $3.17 per MMBtu of natural gas during 2018.

Capital Expenditures

Fourth quarter capital expenditures were $0.2 million. Net capital expenditures incurred during 2018 totaled $46.8 million and were attributable to drilling and development ($39.4 million), infrastructure projects and equipment ($6.6 million), exploratory project ($0.4 million) and acreage acquisitions and extensions ($0.4 million).

Liquidity Update

At December 31, 2018, we had a $1 billion senior secured revolving credit facility in place with a borrowing base of $325 million, and liquidity of $23.2 million. Our credit facility is subject to scheduled redeterminations of our borrowing base semi-annually, based on our reserves. Our next anticipated redetermination is expected to take place in the second quarter of 2019, although our lender has the option to redetermine our borrowing base outside of our anticipated schedule. Continued low commodity prices may adversely impact the results of the upcoming redetermination, and have a significant negative impact on the Company’s liquidity. If our borrowing base is reduced below the amount outstanding under our credit agreement, we may be required to repay a portion of our outstanding borrowings, and we may not have sufficient liquidity to meet this requirement. 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 19% of 2019 forecasted oil and 19% 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 2019 — December 2019      Collar      500 Bbls/day      $65.00/Bbl - $71.00/Bbl 
                   
NGLs (C2 - Ethane)                   
January 2019 — March 2019      Swap      900 Bbls/day      $14.123/Bbl 
NGLs (C3 - Propane)                   
January 2019 — March 2019      Swap      600 Bbls/day      $35.165/Bbl 
January 2019 — June 2019      Swap      75 Bbls/day      $42.00/Bbl 
NGLs (NC4 - Butane)                   
January 2019 — March 2019      Swap      200 Bbls/day      $38.63/Bbl 
NGLs (C5 - Pentane)                   
January 2019 — December 2019      Swap      100 Bbls/day      $65.10/Bbl 
January 2019 — December 2019      Swap      100 Bbls/day      $65.31/Bbl 
                   

Guidance

The Company’s capital budget for 2019 is a range of $30 million to $60 million, depending on commodity prices. The table below sets forth our production and operating costs and expenses guidance for 2019, anticipating a capital budget of $30 million funded primarily through cash flows from operations. The eventual results of our strategic and deleveraging efforts may have a substantial impact on the Company’s ability to achieve the guidance set forth below.

      2019 Guidance 
Capital Expenditures (in millions)      $30 
       
Production:       
Oil (MBbls)      925 − 975 
NGLs (MBbls)      1,250 − 1,350 
Gas (MMcf)      8,650 − 8,750 
Total (MBoe)      3,600 − 3,800 
       
Cash operating costs (per Boe):       
Lease operating      $5.00 − 6.00 
Production and ad valorem taxes      8.5% of oil and gas revenues 
Cash general and administrative      $4.50 − 5.50 
Non-cash operating costs (per Boe):       
Non-cash general and administrative      $0.75 − 1.25 
Exploration      $0.25 − 0.75 
Depletion, depreciation and amortization      $15.00 − 17.00 
       

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 2019 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 Tuesday, March 19, 2019, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss fourth quarter and full-year 2018 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, , or by phone:

Dial in:      (844) 884-9950 / Conference ID: 6089010 
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: 6089010 
       

In addition, a fourth quarter and full-year 2018 summary presentation will be available on the Company’s website.

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd