Fourth Quarter 2016 Highlights
- Production was 12.0 MBoe/d, exceeding quarterly guidance
- Record low quarterly lease operating expense (“LOE”) of
$3.40 per Boe - Cash operating expenses decreased 14% from the prior-year quarter
- Revenues were
$26.5 million , an increase of 12% from the prior quarter
Full-Year 2016 and Other Highlights
- Production was 12.4 MBoe/d, exceeding midpoint of annual guidance
- Record low annual LOE of
$4.24 per Boe - Record low drilling and completion costs of
$3.5 million per well, a reduction of 22% over prior year - Drilled six and completed five wells using positive cash flow generated from our operations, with no increase in debt
- We are encouraged with the results of our new generation completions and once we have additional production data we plan to update our type curves to reflect the EUR improvements
- Reserve replacement ratio of 350%
- Reached an agreement to reduce senior note debt by
$130.6 million and future interest expense by$40 million through debt-for-equity exchange, subsequently closed inJanuary 2017
Management Comment
Fourth Quarter 2016 Results
Production for fourth quarter 2016 totaled 1,106 MBoe (12.0 MBoe/d), made up of 28% oil, 34% NGLs and 38% natural gas. Average realized commodity prices for fourth quarter 2016, before the effect of commodity derivatives, were
Net loss for fourth quarter 2016 was
LOE averaged
Full-Year 2016 Results
Production for 2016 was 4,537 MBoe (12.4 MBoe/d), made up of 28% oil, 34% NGLs and 38% natural gas. Average realized commodity prices for 2016, before the effect of commodity derivatives, were
Net loss for 2016 was
LOE averaged
Adjusted net loss, EBITDAX, cash operating expenses and PV-10 are non-GAAP measures. See “Supplemental Non-GAAP Financial and Other Measures” below for our definitions and reconciliations of adjusted net loss and EBITDAX to net loss, cash operating expenses to operating expenses and PV-10 to the standardized measure (GAAP) and our definition and calculation of liquidity.
Operations Update
In 2016, we focused on operating within cash flow while managing natural production decline, improving cost structure and increasing efficiencies. During 2016, we drilled a total of six horizontal wells and completed five. Of these, two wells were drilled to the A bench, one well was drilled to the B bench and three wells were drilled to the C bench. The five completed wells are tracking at a type curve of approximately 678 Mboe, including one well normalized for a 7,500 foot lateral length. At
With our new generation frac design, we are very encouraged by the well results and expect to update our type curves to reflect the EUR improvements once we have additional production data. We currently are running one horizontal rig in Project Pangea and have completed two University wells that are in the early stage of flowback.
We managed our natural production decline through surface facility optimization, operating efficiencies and investment in well repairs, workovers and maintenance. During the first quarter of 2016, our production decreased by 12% compared to the prior quarter due to no new well completions from
Our extensive infrastructure network of centralized production facilities, water transportation, handling and recycling system, gas lift lines and salt water disposal wells continue to provide competitive advantages in driving down drilling and completion, and operating costs. In 2016, we were able to reduce our drilling and completion costs by 22% to
Strategic Deleveraging Transaction
On
Immediately following the close of the exchange, we launched an offer to exchange our common stock for the remaining
Fourth Quarter and Full-Year 2016 Production
Estimated fourth quarter 2016 production totaled 1,106 MBoe (12.0 MBoe/d). Estimated full-year 2016 production totaled 4,537 MBoe (12.4 MBoe/d).
| Three and 12 Months Ended December 31, 2016 |
|||||
| Three months |
12 months | ||||
| Production: | |||||
| Oil (MBbls) | 304 | 1,275 | |||
| NGLs (MBbls) | 380 | 1,529 | |||
| Gas (MMcf) | 2,530 | 10,404 | |||
| Total (MBoe) | 1,106 | 4,537 | |||
| Total (MBoe/d) | 12.0 | 12.4 | |||
2016 Estimated Proved Reserves and Costs Incurred
Year-end 2016 proved reserves totaled 156.4 MMBoe. Year-end 2016 proved reserves were 32% oil, 30% NGLs and 38% natural gas. Proved developed reserves represent approximately 38% of total year-end 2016 proved reserves.
At
The table below illustrates our horizontal Wolfcamp and other reserves over the last three years ended
| Proved Reserves (Mboe) | ||||||||
| 2016 |
2015 |
2014 |
||||||
| Horizontal Wolfcamp | ||||||||
| Proved developed | 47,861 | 49,843 | 40,678 | |||||
| Proved undeveloped | 97,502 | 104,790 | 84,138 | |||||
| Total | 145,363 | 154,633 | 124,816 | |||||
| Percent of total proved reserves | 93 | % | 93 | % | 85 | % | ||
| Other Vertical | ||||||||
| Proved developed | 11,014 | 12,013 | 19,542 | |||||
| Proved undeveloped | - | - | 1,890 | |||||
| Total | 11,014 | 12,013 | 21,432 | |||||
| Percent of total proved reserves | 7 | % | 7 | % | 15 | % | ||
| Total proved reserves | 156,377 | 166,646 | 146,248 | |||||
Extensions and discoveries for 2016 were 16.7 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the
The following table summarizes the changes in our estimated proved reserves during 2016.
| Oil (MBbls) |
NGLs (MBbls) |
Natural Gas (MMcf) |
Total (MBoe) |
|||||||||
| Balance – December 31, 2015 | 54,496 | 49,486 | 375,988 | 166,646 | ||||||||
| Extensions and discoveries | 6,529 | 4,564 | 33,347 | 16,651 | ||||||||
| Production (1) | (1,275 | ) | (1,529 | ) | (11,734 | ) | (4,759 | ) | ||||
| Revisions | (9,719 | ) | (4,887 | ) | (45,324 | ) | (22,161 | ) | ||||
| Balance – December 31, 2016 | 50,031 | 47,634 | 352,277 | 156,377 | ||||||||
| Reserve replacement ratio | ||||||||||||
| Extensions and discoveries / Production | 350% | |||||||||||
| (1) Production includes 1,330 MMcf related to field fuel. |
||||||||||||
Our preliminary, unaudited estimate of the standardized after-tax measure of discounted future net cash flows (“standardized measure”) of our proved reserves at
The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2016 proved reserves and PV-10 at
At NYMEX strip pricing at
| 2017 | 2018 | 2019 | 2020 | 2021(1) | ||||||||||||||
| Oil (per Bbl) | $ | 56.19 | $ | 56.59 | $ | 56.10 | $ | 56.05 | $ | 56.21 | ||||||||
| Natural Gas (per MMBtu) | $ | 3.61 | $ | 3.14 | $ | 2.87 | $ | 2.88 | $ | 2.90 | ||||||||
| (1) Subsequent year prices were held flat for the remaining lives of the properties. | ||||||||||||||||||
| (2) NGLs prices per Bbl were estimated at 40% of the oil strip price. | ||||||||||||||||||
Net capital expenditures incurred during 2016 totaled
Guidance
The Company’s capital budget for 2017 is a range of
| 2017 Guidance | ||
| Capital expenditures (in millions) | $50 – $70 | |
| Production: |
||
| Oil (MBbls) | 1,200 – 1,300 | |
| NGLs (MBbls) | 1,380 – 1,460 | |
| Gas (MMcf) | 9,500 – 10,160 | |
| Total (MBoe) | 4,163 – 4,453 | |
| Cash operating costs (per Boe): | ||
| Lease operating | $ | 4.00 – 5.00 |
| Production and ad valorem taxes | 8.5% of oil & gas revenues | |
| Cash general and administrative | $ | 4.00 – 5.00 |
| Non-cash operating costs (per Boe): | ||
| Non-cash general and administrative | $ | 1.00 – 1.50 |
| Exploration | $ | 0.50 – 1.00 |
| Depletion, depreciation and amortization | $ | 17.00 – 19.00 |
First quarter 2017 production is estimated to be approximately 11.3 MBoe/d. First quarter 2017 production will be affected by no new well completions in the fourth quarter of 2016, weather and RVP pipeline specification issues in first quarter 2017. We expect to resume quarterly production growth starting in the second quarter of 2017.
As further discussed below under “Forward-Looking and Cautionary Statements,” our guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond our control. In addition, our 2017 capital budget excludes acquisitions and lease extensions and renewals and is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil, NGLs and natural gas, results of horizontal drilling and completions, economic and industry conditions at the time of drilling, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.
Liquidity Update
At
Commodity Derivatives Update
We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. At present, approximately 85% of 2017 forecasted natural gas and 50% of NGL production is hedged. The table below is a summary of our current derivatives positions.
| Commodity and Period | Contract Type |
Volume Transacted | Contract Price | |||
| Natural Gas | ||||||
| January 2017 — March 2017 | Swap | 100,000 MMBtu/month | $2.463/MMBtu | |||
| January 2017 — March 2017 | Swap | 300,000 MMBtu/month | $2.45/MMBtu | |||
| January 2017 — March 2017 | Swap | 200,000 MMBtu/month | $3.287/MMBtu | |||
| January 2017 — December 2017 | Collar | 100,000 MMBtu/month | $3.00/MMBtu - $3.65/MMBtu | |||
| April 2017 — December 2017 | Collar | 200,000 MMBtu/month | $2.30/MMBtu - $2.60/MMBtu | |||
| April 2017 — December 2017 | Collar | 200,000 MMBtu/month | $3.00/MMBtu - $3.44/MMBtu | |||
| April 2017 — December 2017 | Collar | 200,000 MMBtu/month | $3.00/MMBtu - $3.50/MMBtu | |||
| January 2018 — December 2018 | Swap | 200,000 MMBtu/month | $3.085/MMBtu | |||
| January 2018 — December 2018 | Swap | 250,000 MMBtu/month | $3.084/MMBtu | |||
| NGLs (C2 - Ethane) | ||||||
| February 2017 — December 2017 | Swap | 1,050 Bbls/day | $11.34/Bbl | |||
| NGLs (C3 - Propane) | ||||||
| February 2017 — December 2017 | Swap | 750 Bbls/day | $27.916/Bbl | |||
| NGLs (IC4 - Isobutane) | ||||||
| February 2017 — December 2017 | Swap | 75 Bbls/day | $36.7325/Bbl | |||
| NGLs (NC4 - Butane) | ||||||
| February 2017 — December 2017 | Swap | 250 Bbls/day | $35.9205/Bbl | |||
Conference Call Information and Summary Presentation
The Company will host a conference call on
| Dial in: | (844) 884-9950 / Conference ID: 70306606 | |
| International Dial In: | (661) 378-9660 | |
| A replay of the call will be available on the Company’s website or by dialing: | ||
| Dial in: | (855) 859-2056 / Passcode: 70306606 | |
In addition, a fourth quarter and full-year 2016 summary presentation will be available on the Company’s website.
About
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
| UNAUDITED RESULTS OF OPERATIONS | ||||||||||||||||||
| Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||||
| Revenues (in thousands): | ||||||||||||||||||
| Oil | $ | 14,007 | $ | 15,028 | $ | 48,311 | $ | 82,170 | ||||||||||
| NGLs | 5,798 | 4,370 | 19,761 | 20,437 | ||||||||||||||
| Gas | 6,700 | 6,094 | 22,230 | 28,729 | ||||||||||||||
| Total oil, NGLs and gas sales | 26,505 | 25,492 | 90,302 | 131,336 | ||||||||||||||
| Realized gain on commodity derivatives | 442 | 14,552 | 6,132 | 52,489 | ||||||||||||||
| Total oil, NGLs and gas sales including derivative impact | $ | 26,947 | $ | 40,044 | $ | 96,434 | $ | 183,825 | ||||||||||
| Production: | ||||||||||||||||||
| Oil (MBbls) | 304 | 400 | 1,275 | 1,882 | ||||||||||||||
| NGLs (MBbls) | 380 | 428 | 1,529 | 1,694 | ||||||||||||||
| Gas (MMcf) | 2,530 | 3,011 | 10,404 | 11,732 | ||||||||||||||
| Total (MBoe) | 1,106 | 1,330 | 4,537 | 5,532 | ||||||||||||||
| Total (MBoe/d) | 12.0 | 14.5 | 12.4 | 15.2 | ||||||||||||||
| Average prices: | ||||||||||||||||||
| Oil (per Bbl) | $ | 46.02 | $ | 37.60 | $ | 37.90 | $ | 43.65 | ||||||||||
| NGLs (per Bbl) | 15.25 | 10.20 | 12.93 | 12.06 | ||||||||||||||
| Gas (per Mcf) | 2.65 | 2.02 | 2.14 | 2.45 | ||||||||||||||
| Total (per Boe) | $ | 23.96 | $ | 19.17 | $ | 19.90 | $ | 23.74 | ||||||||||
| Realized gain on commodity derivatives (per Boe) | 0.40 | 10.94 | 1.35 | 9.49 | ||||||||||||||
| Total including derivative impact (per Boe) | $ | 24.36 | $ | 30.11 | $ | 21.25 | $ | 33.23 | ||||||||||
| Costs and expenses (per Boe): | ||||||||||||||||||
| Lease operating | $ | 3.40 | $ | 5.44 | $ | 4.24 | $ | 5.24 | ||||||||||
| Production and ad valorem taxes | 2.43 | 1.94 | 1.81 | 2.00 | ||||||||||||||
| Exploration | 0.62 | 0.17 | 0.86 | 0.80 | ||||||||||||||
| General and administrative(1) | 6.35 | 4.10 | 5.45 | 5.12 | ||||||||||||||
| Depletion, depreciation and amortization | 17.54 | 17.42 | 17.42 | 19.76 | ||||||||||||||
| (1) Below is a summary of general and administrative expense: | ||||||||||||||||||
| General and administrative – cash Component | $ | 4.55 | $ | 2.63 | $ | 4.07 | $ | 3.68 | ||||||||||
| General and administrative – noncash Component | 1.80 | 1.47 | 1.38 | 1.44 | ||||||||||||||
| APPROACH RESOURCES INC. AND SUBSIDIARIES | ||||||||||||||||
| UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||||||||||
| (In thousands, except shares and per-share amounts) | ||||||||||||||||
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| REVENUES: | ||||||||||||||||
| Oil, NGLs and gas sales | $ | 26,505 | $ | 25,492 | $ | 90,302 | $ | 131,336 | ||||||||
| EXPENSES: | ||||||||||||||||
| Lease operating | 3,766 | 7,228 | 19,250 | 28,972 | ||||||||||||
| Production and ad valorem taxes | 2,685 | 2,583 | 8,217 | 11,085 | ||||||||||||
| Exploration | 685 | 228 | 3,923 | 4,439 | ||||||||||||
| General and administrative | 7,026 | 5,459 | 24,734 | 28,341 | ||||||||||||
| Termination costs | – | – | – | 1,436 | ||||||||||||
| Impairment of oil and gas properties | – | – | – | 220,197 | ||||||||||||
| Depletion, depreciation and amortization | 19,402 | 23,173 | 79,044 | 109,319 | ||||||||||||
| Total expenses | 33,564 | 38,671 | 135,168 | 403,789 | ||||||||||||
| OPERATING LOSS | (7,059 | ) | (13,179 | ) | (44,866 | ) | (272,453 | ) | ||||||||
| OTHER: | ||||||||||||||||
| Interest expense, net | (7,086 | ) | (6,436 | ) | (27,259 | ) | (25,066 | ) | ||||||||
| Gain on debt extinguishment | – | 9,080 | – | 10,563 | ||||||||||||
| Write-off of debt issuance costs | – | – | (563 | ) | – | |||||||||||
| Realized gain on commodity derivatives | 442 | 14,552 | 6,132 | 52,489 | ||||||||||||
| Unrealized loss on commodity derivatives | (3,343 | ) | (10,285 | ) | (11,616 | ) | (33,214 | ) | ||||||||
| Other income | – | 225 | 1,511 | 172 | ||||||||||||
| LOSS BEFORE INCOME TAX BENEFIT | (17,046 | ) | (6,043 | ) | (76,661 | ) | (267,509 | ) | ||||||||
| INCOME TAX BENEFIT: | ||||||||||||||||
| Current | – | (265 | ) | – | (265 | ) | ||||||||||
| Deferred | (3,571 | ) | (19 | ) | (24,418 | ) | (93,140 | ) | ||||||||
| NET LOSS | $ | (13,475 | ) | $ | (5,759 | ) | $ | (52,243 | ) | $ | (174,104 | ) | ||||
| EARNINGS PER SHARE: | ||||||||||||||||
| Basic | $ | (0.32 | ) | $ | (0.14 | ) | $ | (1.26 | ) | $ | (4.30 | ) | ||||
| Diluted | $ | (0.32 | ) | $ | (0.14 | ) | $ | (1.26 | ) | $ | (4.30 | ) | ||||
| WEIGHTED AVERAGE SHARES OUTSTANDING: | ||||||||||||||||
| Basic | 41,705,462 | 40,598,098 | 41,488,206 | 40,464,283 | ||||||||||||
| Diluted | 41,705,462 | 40,598,098 | 41,488,206 | 40,464,283 | ||||||||||||
| UNAUDITED SELECTED FINANCIAL DATA | ||||||||
| Unaudited Consolidated Balance Sheet Data | December 31, | |||||||
| (in thousands) | 2016 | 2015 | ||||||
| Cash and cash equivalents | $ | 21 | $ | 600 | ||||
| Other current assets | 12,473 | 19,838 | ||||||
| Property and equipment, net, successful efforts method | 1,092,061 | 1,154,546 | ||||||
| Total assets | $ | 1,104,555 | $ | 1,174,984 | ||||
| Current liabilities | $ | 26,369 | $ | 28,508 | ||||
| Long-term debt (1) | 498,349 | 496,587 | ||||||
| Other long-term liabilities | 16,885 | 41,922 | ||||||
| Stockholders’ equity | 562,952 | 607,967 | ||||||
| Total liabilities and stockholders’ equity | $ | 1,104,555 | $ | 1,174,984 | ||||
| (1) Long-term debt at December 31, 2016, is comprised of $230.3 million in 7% senior notes due 2021 and $273 million in outstanding borrowings under our senior secured credit facility, net of issuance costs of $5 million. Long-term debt at December 31, 2015, is comprised of $230.3 million in 7% senior notes due 2021 and $273 million in outstanding borrowings under our senior secured credit facility, net of issuance costs of $6.7 million. | ||||||||
| Unaudited Consolidated Cash Flow Data | Twelve Months Ended December 31, | ||||||
| (in thousands) | 2016 | 2015 | |||||
| Net cash provided (used) by: | |||||||
| Operating activities | $ | 26,081 | $ | 102,716 | |||
| Investing activities | $ | (23,890 | ) | $ | (217,347 | ) | |
| Financing activities | $ | (2,770 | ) | $ | 114,799 | ||
Supplemental Non-GAAP Financial and Other Measures
This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations below of the non-GAAP financial measures to the most directly comparable GAAP financial measures and on the Non-GAAP Financial Information page under the Financial Reporting subsection of the Investor Relations section of our website at www.approachresources.com.
Adjusted Net Loss
This release contains the non-GAAP financial measures adjusted net loss and adjusted net loss per diluted share, which exclude (1) unrealized loss on commodity derivatives, (2) write-off of debt issuance costs, (3) rig termination fees, (4) impairment of oil and gas properties, (5) termination costs, (6) gain on debt extinguishment, and (7) related income tax effect. The amounts included in the calculation of adjusted net loss and adjusted net loss per diluted share below were computed in accordance with GAAP. We believe adjusted net loss and adjusted net loss per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our
The table below provides a reconciliation of adjusted net loss to net loss for the three and twelve months ended
| Three Months Ended December 31, |
Twelve Months Ended December 31, |
||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Net loss | $ | (13,475 | ) | $ | (5,759 | ) | $ | (52,243 | ) | $ | (174,104 | ) | |||
| Adjustments for certain items: | |||||||||||||||
| Unrealized loss on commodity derivatives | 3,343 | 10,285 | 11,616 | 33,214 | |||||||||||
| Write-off of debt issuance costs | – | – | 563 | – | |||||||||||
| Rig termination fees | – | – | – | 2,199 | |||||||||||
| Impairment of oil and gas properties | – | – | – | 220,197 | |||||||||||
| Termination costs | – | – | – | 1,436 | |||||||||||
| Gain on debt extinguishment | – | (9,080 | ) | – | (10,563 | ) | |||||||||
| Related income tax effect | (1,170 | ) | (422 | ) | (4,263 | ) | (87,348 | ) | |||||||
| Adjusted net loss | $ | (11,302 | ) | $ | (4,976 | ) | $ | (44,327 | ) | $ | (14,969 | ) | |||
| Adjusted net loss per diluted share | $ | (0.27 | ) | $ | (0.12 | ) | $ | (1.07 | ) | $ | (0.37 | ) | |||
EBITDAX
We define EBITDAX as net loss, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) impairment of oil and gas properties, (6) termination costs, (7) gain on debt extinguishment, (8) write-off of debt issuance costs, (9) interest expense, net, and (10) income tax benefit. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net loss because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our
The table below provides a reconciliation of EBITDAX to net loss for the three and twelve months ended
| Three Months Ended December 31, |
Twelve Months Ended December 31, |
||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Net loss | $ | (13,475 | ) | $ | (5,759 | ) | $ | (52,243 | ) | $ | (174,104 | ) | |||
| Exploration | 685 | 228 | 3,923 | 4,439 | |||||||||||
| Depletion, depreciation and amortization | 19,402 | 23,173 | 79,044 | 109,319 | |||||||||||
| Share-based compensation | 1,998 | 1,954 | 6,279 | 7,954 | |||||||||||
| Unrealized loss on commodity derivatives | 3,343 | 10,285 | 11,616 | 33,214 | |||||||||||
| Impairment of oil and gas properties | – | – | – | 220,197 | |||||||||||
| Termination costs | – | – | – | 1,436 | |||||||||||
| Gain on debt extinguishment | – | (9,080 | ) | – | (10,563 | ) | |||||||||
| Write-off of debt issuance costs | – | – | 563 | – | |||||||||||
| Interest expense, net | 7,086 | 6,436 | 27,259 | 25,066 | |||||||||||
| Income tax benefit | (3,571 | ) | (284 | ) | (24,418 | ) | (93,405 | ) | |||||||
| EBITDAX | $ | 15,468 | $ | 26,953 | $ | 52,023 | $ | 123,553 | |||||||
Cash Operating Expenses
We define cash operating expenses as operating expenses, excluding (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) termination costs, and (5) impairment of oil and gas properties. Cash operating expenses is not a measure of operating expenses as determined by GAAP. The amounts included in the calculation of cash operating expenses were computed in accordance with GAAP. Cash operating expenses is presented herein and reconciled to the GAAP measure of operating expenses. We use cash operating expenses as an indicator of the Company’s ability to manage its operating expenses and cash flows. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our
The table below provides a reconciliation of cash operating expenses to operating expenses for the three and twelve months ended
| Three Months Ended December 31, |
Twelve Months Ended December 31, |
||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Operating expenses | $ | 33,564 | $ | 38,671 | $ | 135,168 | $ | 403,789 | |||||||
| Exploration | (685 | ) | (228 | ) | (3,923 | ) | (4,439 | ) | |||||||
| Depletion, depreciation and amortization | (19,402 | ) | (23,173 | ) | (79,044 | ) | (109,319 | ) | |||||||
| Share-based compensation | (1,998 | ) | (1,954 | ) | (6,279 | ) | (7,954 | ) | |||||||
| Termination costs | — | — | — | (1,436 | ) | ||||||||||
| Impairment of oil and gas properties | — | — | — | (220,197 | ) | ||||||||||
| Cash operating expenses | $ | 11,479 | $ | 13,316 | $ | 45,922 | $ | 60,444 | |||||||
| Cash operating expenses per Boe | $ | 10.38 | $ | 10.01 | $ | 10.12 | $ | 10.93 | |||||||
PV-10
The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at
PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.
The table below reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.
| (in millions) | December 31, 2016 | |||
| PV-10 | $ | 307.9 | ||
| Less income taxes: | ||||
| Undiscounted future income taxes | (132.8 | ) | ||
| 10% discount factor | 122.7 | |||
| Future discounted income taxes | (10.1 | ) | ||
| Standardized measure of discounted future net cash flows | $ | 297.8 | ||
Liquidity
Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company’s ability to fund development and exploration activities. However, this measurement has limitations. This measurement can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the measurement on a company’s financial statements. This measurement is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our
The table below summarizes our liquidity at
| Liquidity at December 31, |
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| 2016 | 2015 | ||||||
| Borrowing base | $ | 325,000 | $ | 450,000 | |||
| Cash and cash equivalents | 21 | 600 | |||||
| Senior secured credit facility – outstanding borrowings | (273,000 | ) | (273,000 | ) | |||
| Outstanding letters of credit | (575 | ) | (325 | ) | |||
| Liquidity | $ | 51,446 | $ | 177,275 | |||
Long-term debt-to-capital ratio is calculated by dividing long-term debt (GAAP) by the sum of total stockholders’ equity (GAAP) and long-term debt (GAAP). We use the long-term debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio has limitations. This ratio can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the ratio on a company’s financial statements. This ratio is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our
The table below summarizes our long-term debt-to-capital ratio at
| Long-Term Debt-to-Capital at December 31, |
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| 2016 | 2015 | ||||||
| Long-term debt (1) | $ | 498,349 | $ | 496,587 | |||
| Total stockholders’ equity | 562,952 | 607,967 | |||||
| $ | 1,061,301 | $ | 1,104,554 | ||||
| Long-term debt-to-capital | 47 | % | 45 | % | |||
| (1) Long-term debt is net of debt issuance costs of $5 million and $6.7 million at December 31, 2016 and December 31, 2015, respectively. |
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INVESTOR CONTACTSuzanne Ogle Vice President Investor Relations & Corporate Communication [email protected] 817.989.9000
