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Approach Resources Inc. Reports Fourth Quarter and Full-Year 2014 Results and Provides 2015 Outlook

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Approach Resources Inc. (NASDAQ:AREX) today reported results for fourth quarter and full-year 2014 and estimated 2014 proved reserves.

Fourth Quarter 2014 Highlights

  • Production was 15.1 MBoe/d, a 34% increase over the prior-year quarter
  • Revenues totaled $55.1 million
  • Net income was $27.0 million, or $0.68 per diluted share
  • Adjusted net income was $3.4 million, or $0.08 per diluted share
  • EBITDAX was $44.3 million, or $1.12 per diluted share, an increase of 8% over the prior-year quarter
  • Capital expenditures of $92.9 million

Full-Year 2014 Highlights

  • Production was 13.8 MBoe/d, a 47% increase over the prior year
  • Revenues were $258.5 million, a 43% increase over the prior year
  • Net income was $56.2 million, or $1.42 per diluted share
  • Adjusted net income was $29.2 million, or $0.74 per diluted share
  • EBITDAX was an annual record of $188.3 million, or $4.78 per diluted share, an increase of 47% over the prior year
  • Capital expenditures of $393.5 million

2014 Proved Reserves Highlights

  • Year-end 2014 proved reserves were 146.2 MMBoe, a 27% increase over year-end 2013 proved reserves
  • PV-10 was $1.4 billion, a 25% increase
  • Reserve replacement ratio of 819%
  • Drill-bit finding and development cost of $8.94 per Boe

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

Management Comment

J. Ross Craft, Approach’s Chairman, Chief Executive Officer and President, commented, “In 2014, Approach was in growth mode, ramping up our drilling activity by more than 50% and delivering record annual production and reserves for the Company. In light of today’s lower commodity price environment, we have taken proactive steps to maintain our commitment to financial discipline and significantly reduce our capital spending budget to align it more closely with our operating cash flow. At the same time, our team has been working hard to find ways to do more with less by reducing costs and improving profitability. So far this year, we have completed construction of a large-scale water recycling facility and have successfully negotiated significant cost reductions from our service companies. We estimate that these initiatives could lead to 15% – 20% reduction in average well drilling and completion costs beginning in the second quarter of 2015 and will materially improve our return on capital. Given our strong balance sheet and lean cost structure, we believe we are well-positioned to sustain a period of low prices while taking advantage of opportunities presented by current market conditions.”

Fourth Quarter 2014 Results

Production for fourth quarter 2014 totaled 1,390 MBoe (15.1 MBoe/d), made up of 39% oil, 29% NGLs and 32% natural gas. Average realized commodity prices for fourth quarter 2014, before the effect of commodity derivatives, were $68.17 per Bbl of oil, $21.04 per Bbl of NGLs and $3.61 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $45.23 per Boe for fourth quarter 2014.

Net income for fourth quarter 2014 was $27.0 million, or $0.68 per diluted share, on revenues of $55.1 million. Net income for fourth quarter 2014 also included an unrealized gain on commodity derivatives of $36.9 million and a realized gain on commodity derivatives of $7.8 million. Excluding the unrealized gain on commodity derivatives, adjusted net income (non-GAAP) for fourth quarter 2014 was $3.4 million, or $0.08 per diluted share. Adjusted net income per diluted share (non-GAAP) for fourth quarter included a $0.04 per diluted share charge for a non-cash deferred tax asset reversal arising from our share-based compensation. EBITDAX (non-GAAP) for fourth quarter 2014 was $44.3 million, an 8% increase over the prior-year period, or $1.12 per diluted share. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net income and EBITDAX to net income.

Lease operating expenses averaged $6.65 per Boe. Production and ad valorem taxes averaged $2.52 per Boe, or 6.4% of oil, NGL and gas sales. Exploration costs were $0.17 per Boe. Cash general and administrative costs averaged $4.30 per Boe. Depletion, depreciation and amortization expense averaged $20.63 per Boe. Interest expense totaled $5.7 million.

Full-Year 2014 Results

Production for 2014 increased 47% to 5,049 MBoe (13.8 MBoe/d), made up of 40% oil, 29% NGLs and 31% natural gas. Average realized commodity prices for 2014, before the effect of commodity derivatives, were $87.69 per Bbl of oil, $28.74 per Bbl of NGLs and $4.16 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $51.67 per Boe for 2014.

Net income for 2014 was $56.2 million, or $1.42 per diluted share, on revenues of $258.5 million. Net income for 2014 included an unrealized gain on commodity derivatives of $42.1 million and a realized gain on commodity derivatives of $2.4 million. Excluding the unrealized gain on commodity derivatives, adjusted net income (non-GAAP) for 2014 was $29.2 million, or $0.74 per diluted share. EBITDAX (non-GAAP) for 2014 was $188.3 million, a record high, or $4.78 per diluted share. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net income and EBITDAX to net income.

Lease operating expenses averaged $6.48 per Boe. Production and ad valorem taxes averaged $3.16 per Boe, or 6.2% of oil, NGL and gas sales. Exploration costs were $0.76 per Boe. Cash general and administrative costs averaged $4.73 per Boe. Depletion, depreciation and amortization expense averaged $21.15 per Boe. Interest expense totaled $21.7 million.

Operations Update

During fourth quarter 2014, we drilled 18 horizontal wells and completed 13 horizontal wells in the Wolfcamp. Two wells were drilled to the A bench, nine wells were drilled to the B bench and seven wells were drilled to the C bench. During 2014, we drilled a total of 68 horizontal wells and completed 64 horizontal wells. Of these, nine wells were drilled to the A bench, 29 wells were drilled to the B bench and 30 wells were drilled to the C bench. At December 31, 2014, we had 13 horizontal wells waiting on completion. Of the wells completed since our third-quarter operations update, the average initial 24-hour production rate for the B and C-bench completions was 795 Boe/d (52% oil), normalizing one short lateral well, and the average initial 24-hour production rate for the A-bench wells, which tend to come online at lower rates and incline as they dewater, was 345 Boe/d (75% oil). Production rates were negatively impacted by severe winter weather in December and January.

During fourth quarter 2014, we continued to execute our manufacturing-style drilling plan, using pad drilling and batch completions to increase efficiencies and further lower our costs. We initiated the construction of a produced water recycling facility, capable of storing 329,000 barrels of processed water, or about five times our current capacity. This facility is expected to come online before the end of the first quarter, allowing us to recycle up to 100% of our produced and flowback water and reduce or eliminate fees for water sourcing, trucking and disposal.

2014 Estimated Proved Reserves and Costs Incurred

Year-end 2014 proved reserves totaled 146.2 MMBoe, up 27% from year-end 2013 proved reserves of 114.7 MMBoe. Our proved oil reserves increased 20% to 55.3 MMBbls, compared to year-end 2013 proved oil reserves of 46.1 MMBbls. Year-end 2014 proved reserves were 38% oil, 28% NGLs and 34% natural gas, compared to 40% oil, 29% NGLs and 31% natural gas at year-end 2013.

Proved developed reserves represent approximately 41% of total year-end 2014 proved reserves, up from 39% at year-end 2013. At December 31, 2014, 99.9% of our proved reserves were located in our core operating area in the southern Midland Basin. Year-end 2014 estimated proved reserves included 124.8 MMBoe attributable to the horizontal Wolfcamp shale play, compared to 81.6 MMBoe at year-end 2013, representing a 53% increase.

The table below illustrates the growing predominance of our horizontal Wolfcamp reserves over the last three years ended December 31, 2014, 2013 and 2012.

Proved Reserves (MBoe)
2014 2013 2012
Horizontal Wolfcamp
Proved developed 40,678 23,520 10,439
Proved undeveloped 84,138 58,073 43,342
Total 124,816 81,593 53,781
Percent of total proved reserves 85% 71% 56%
Other Vertical
Proved developed 19,542 21,669 22,336
Proved undeveloped 1,890 11,399 19,362
Total 21,432 33,068 41,698
Percent of total proved reserves 15% 29% 44%
Total proved reserves 146,248 114,661 95,479

During 2014, we recorded downward revisions totaling 6.4 MMBoe, including the reclassification of 9.3 MMBoe of proved undeveloped reserves to probable undeveloped. Revisions also included 6.3 MMBoe of positive net revisions attributable to updated well performance and 0.7 MMBoe of positive revisions due to pricing, offset by 4.1 MMBoe of negative revisions resulting from updated technical parameters and costs.

The following table summarizes the changes in our estimated proved reserves during 2014.

Oil

(MBbl)

NGLs

(MBbl)

Natural Gas
(MMcf)

Total

(MBoe)

Balance – December 31, 2013 46,067 32,593 216,002 114,661
Extensions and discoveries 19,347 10,658 79,454 43,247
Production (1) (2,024 ) (1,461 ) (10,773 ) (5,281 )
Revisions (8,052 ) (883 ) 15,337 (6,379 )
Balance – December 31, 2014 55,338 40,907 300,020 146,248

(1) Production includes 1,390 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, 2014, was $1.1 billion. The PV-10, or pre-tax present value of our proved reserves discounted at 10%, of our proved reserves at December 31, 2014, was $1.4 billion, compared to $1.1 billion at year-end 2013. The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2014 proved reserves and PV-10. PV-10 is a non-GAAP measure. See “Supplemental Non-GAAP Measures” below for our definition of PV-10 and a reconciliation to the Standardized Measure (GAAP). Estimates of year-end 2014 proved reserves and PV-10 were prepared using $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu of natural gas.

Capital expenditures incurred during 2014 totaled $393.5 million and included $364 million for drilling and completion activities, $24.9 million for infrastructure projects and other equipment and $4.6 million for acreage acquisitions and lease extensions.

2015 Guidance

In December 2014, we announced a capital spending budget for 2015 of $180 million. Given the continued decline in crude oil prices, we have further reduced our spending plans by an additional 11% to approximately $160 million, including up to $9 million for infrastructure expenses. We plan to operate an average of one rig in 2015, compared to three rigs in 2014, with the flexibility to increase or decrease the number of rigs running depending on market conditions. The table below sets forth the Company’s current production and operating costs and expenses guidance for 2015.

2015 Guidance
Production:
Oil (MBbls) 2,200 – 2,325
NGLs (MBbls) 1,575 – 1,625
Gas (MMcf) 10,050 – 10,200
Total (MBoe) 5,450 – 5,650
Operating costs and expenses (per Boe):
Lease operating $6.00 – 7.00
Production and ad valorem taxes 7.25% of oil & gas revenues
Cash general and administrative

$3.75 – 4.25

Exploration (non-cash)

$0.50 – 1.00
Depletion, depreciation and amortization

$20.00 – 22.00

Capital expenditures (in millions)

Approximately $160

The Company’s guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control. In addition, our 2015 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; additional data on the Company’s Wolfcamp shale oil resource play; results of horizontal drilling and completions, including pad drilling and batch completions; economic and industry conditions at the time of drilling; the availability of sufficient capital resources for drilling prospects; the Company’s financial results and the availability of lease extensions and renewals on reasonable terms.

Liquidity Update

At December 31, 2014, we had a $1 billion senior secured revolving credit facility in place. The borrowing base increased to $600 million following the 2014 fall bank redetermination; however, we have elected to leave the aggregate commitment amount at $450 million. At December 31, 2014, our liquidity and long-term debt-to-capital ratio were approximately $300.1 million and 34.1%, respectively. See “Supplemental Non-GAAP Financial and Other Measures” below for our definitions and calculation of liquidity and long-term debt-to-capital.

Commodity Derivatives Update

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

Commodity and Period Contract Type Volume Transacted Contract Price
Crude Oil
January 2015 – March 2015 Collar 1,500 Bbls/d $85.00/Bbl – $95.30/Bbl
January 2015 – December 2015 Collar 1,600 Bbls/d $84.00/Bbl – $91.00/Bbl
January 2015 – December 2015 Collar 1,000 Bbls/d $90.00/Bbl – $102.50/Bbl
January 2015 – December 2015 Three-Way Collar 500 Bbls/d $75.00/Bbl – $84.00/Bbl – $94.00/Bbl
January 2015 – December 2015 Three-Way Collar 500 Bbls/d $75.00/Bbl – $84.00/Bbl – $95.00/Bbl
Natural Gas
January 2015 – June 2015 Collar 80,000 MMBtu/month $4.00/MMBtu – $4.74/MMBtu
January 2015 – December 2015 Swap 200,000 MMBtu/month $4.10/MMBtu
January 2015 – December 2015 Collar 130,000 MMBtu/month $4.00/MMBtu – $4.25/MMBtu

Conference Call Information and Summary Presentation

The Company will host a conference call on Thursday, February 26, 2015, at 9:00 a.m. Central Time (10:00 a.m. Eastern Time) to discuss financial and operational results for the fourth quarter and full-year 2014. 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: (877) 201-0168
Intl. dial in: (647) 788-4901
Passcode: Approach/76119425

A replay of the call will be available on the Company’s website or by dialing:

Dial in: (855) 859-2056
Passcode: 76119425

In addition, a fourth quarter and full-year 2014 summary presentation will be available on the Company’s website.

About Approach Resources

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

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include expectations of anticipated financial and operating results. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions, risks and uncertainties is available in the Company’s Securities and Exchange Commission (“SEC”) filings. The Company’s SEC filings are available on the Company’s website at www.approachresources.com. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

UNAUDITED RESULTS OF OPERATIONS

Three Months Ended

December 31,

Twelve Months Ended

December 31,

2014 2013 2014 2013
Revenues (in thousands):
Oil $ 36,982 $ 43,421 $ 177,491 $ 130,971
NGLs 8,512 8,421 41,998 28,103
Gas 9,576 6,723 39,040 22,228
Total oil, NGL and gas sales 55,070 58,565 258,529 181,302
Realized gain (loss) on commodity derivatives 7,782 199 2,359 (1,048 )
Total oil, NGL and gas sales including derivative impact $ 62,852 $ 58,764 $ 260,888 $ 180,254
Production:
Oil (MBbls) 542 475 2,024 1,444
NGLs (MBbls) 404 268 1,461 951
Gas (MMcf) 2,656 1,784 9,383 6,177
Total (MBoe) 1,390 1,041 5,049 3,424
Total (MBoe/d) 15.1 11.3 13.8 9.4
Average prices:
Oil (per Bbl) $ 68.17 $ 91.34 $ 87.69 $ 90.70
NGLs (per Bbl) 21.04 31.41 28.74 29.57
Gas (per Mcf) 3.61 3.77 4.16 3.60
Total (per Boe) $ 39.63 $ 56.27 $ 51.20 $ 52.95
Realized gain (loss) on commodity derivatives (per Boe) 5.60 0.19 0.47 (0.31 )
Total including derivative impact (per Boe) $ 45.23 $ 56.46 $ 51.67 $ 52.64
Costs and expenses (per Boe):
Lease operating $ 6.65

$

5.19

$

6.48

$ 5.59
Production and ad valorem taxes 2.52 3.89 3.16 3.75
Exploration 0.17 0.22 0.76 0.65

General and administrative(1)

6.11 8.37 6.36 7.75
Depletion, depreciation and amortization 20.63 21.14 21.15 22.48

(1) Below is a summary of general and administrative expense:

General and administrative – cash component

$

4.30

$

7.88

$

4.73

$

6.02

General and administrative – noncash component

1.81

0.49

1.63

1.73

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,
2014 2013 2014 2013
REVENUES:
Oil, NGL and gas sales $ 55,070 $ 58,565 $ 258,529 $ 181,302
EXPENSES:
Lease operating 9,239 5,406 32,701 19,152
Production and ad valorem taxes 3,505 4,049 15,934 12,840
Exploration 236 228 3,831 2,238
General and administrative 8,492 8,714 32,104 26,524
Depletion, depreciation and amortization 28,664 22,005 106,802 76,956
Total expenses 50,136 40,402 191,372 137,710
OPERATING INCOME 4,934 18,163 67,157 43,592
OTHER:
Interest expense, net (5,715 ) (5,225 ) (21,651 ) (14,084 )

Equity in earnings (losses) of investee

5 (4 ) (181 ) 156
Gain on sale of equity method investment 90,743 90,743
Realized gain (loss) on commodity derivatives 7,782 199 2,359 (1,048 )

Unrealized gain (loss) on commodity derivatives

36,907 (1,348 ) 42,113 (4,596 )
Other income 176 67
INCOME BEFORE INCOME TAX PROVISION 44,089 102,528 89,864 114,763
INCOME TAX (BENEFIT) PROVISION:
Current (25 ) 429 (25 ) 429
Deferred 17,127 37,778 33,717 42,078
NET INCOME $ 26,987 $ 64,321 $ 56,172 $ 72,256
EARNINGS PER SHARE:
Basic $ 0.68 $ 1.65 $ 1.43 $ 1.85
Diluted $ 0.68 $ 1.65 $ 1.42 $ 1.85
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 39,651,587 39,047,495 39,407,733 38,997,815
Diluted 39,651,587 39,067,553 39,419,865 39,019,149

UNAUDITED SELECTED FINANCIAL DATA

Unaudited Consolidated Balance Sheet Data December 31,
(in thousands) 2014 2013
Cash and cash equivalents $ 432 $ 58,761
Restricted cash 7,350
Other current assets 60,647 24,302
Property and equipment, net, successful efforts method 1,331,659 1,047,030
Equity method investment
Other assets 8,689 8,041
Total assets $ 1,401,427 $ 1,145,484
Current liabilities $ 106,852 $ 84,441
Long-term debt (1) 400,000 250,000
Other long-term liabilities 120,248 100,548
Stockholders’ equity 774,327 710,495
Total liabilities and stockholders’ equity $ 1,401,427 $ 1,145,484
(1)

Long-term debt at December 31, 2014, is comprised of $250 million in 7% senior notes due 2021 and $150 million in outstanding borrowings under our senior secured credit facility. Long-term debt at December 31, 2013, is comprised of $250 million in 7% senior notes due 2021.

Unaudited Consolidated Cash Flow Data Twelve Months Ended December 31,
(in thousands) 2014 2013
Net cash provided (used) by:
Operating activities $ 180,206 $ 125,580
Investing activities $ (386,361 ) $ (203,397 )
Financing activities $ 147,826 $ 135,811

Supplemental Non-GAAP Financial and Other Measures

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

Adjusted Net Income

This release contains the non-GAAP financial measures adjusted net income and adjusted net income per diluted share, which excludes an unrealized loss (gain) on commodity derivatives, gain on the sale of our equity method investment and related income taxes. The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more 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 income to net income for the three and twelve months ended December 31, 2014 and 2013 (in thousands, except per-share amounts).

Three Months Ended

December 31,

Twelve Months Ended

December 31,

2014 2013 2014 2013
Net income $ 26,987 $ 64,321 $ 56,172 $ 72,256
Adjustments for certain items:
Unrealized (gain) loss on commodity derivatives (36,907 ) 1,348 (42,113 ) 4,596
Gain on sale of equity method investment (90,743 ) (90,743 )
Related income tax effect 13,287 33,076 15,161 31,874
Adjusted net income $ 3,367 $ 8,002 $ 29,220 $ 17,983
Adjusted net income per diluted share $ 0.08 $ 0.20 $ $0.74 $ 0.46

EBITDAX

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

The table below provides a reconciliation of EBITDAX to net income for the three and twelve months ended December 31, 2014 and 2013 (in thousands, except per-share amounts).

Three Months Ended

December 31,

Twelve Months Ended

December 31,

2014 2013 2014 2013
Net income $ 26,987 $ 64,321 $ 56,172 $ 72,256
Exploration 236 228 3,831 2,238
Gain on sale of equity method investment (90,743 ) (90,743 )
Depletion, depreciation and amortization 28,664 22,005 106,802 76,956
Share-based compensation 2,521 512 8,247 5,901
Unrealized (gain) loss on commodity derivatives (36,907 ) 1,348 (42,113 ) 4,596
Interest expense, net 5,715 5,225 21,651 14,084
Income tax provision 17,102 38,207 33,692 42,507
EBITDAX $ 44,318 $ 41,103 $ 188,282 $ 127,795
EBITDAX per diluted share $ 1.12 $ 1.05 $ 4.78 $ 3.28

PV-10

The present value of our proved reserves, discounted at 10% (“PV-10″), was estimated at $1.4 billion at December 31, 2014, and was calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and natural gas, of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu of natural gas.

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, 2014
PV-10 $ 1,413
Less income taxes:
Undiscounted future income taxes (1,267 )
10% discount factor 910
Future discounted income taxes (357 )
Standardized measure of discounted future net cash flows $ 1,056

Finding and Development Costs

All-in finding and development (“F&D”) costs are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year by the sum of reserve extensions and discoveries, purchases of minerals in place and total revisions for the year.

Drill-bit F&D costs are calculated by dividing the sum of exploration costs and development costs for the year by the total of reserve extensions and discoveries for the year.

We believe that providing the above measures of F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and to be included in our annual report on Form 10-K to be filed with the SEC on or before February 26, 2015. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases.

As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company’s future F&D costs will not differ materially from those set forth above. Further, the methods used by us to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies.

The table below reconciles our estimated F&D costs for 2014 to the information required by paragraphs 11 and 21 of ASC 932-235:

Cost summary (in thousands)
Property acquisition costs
Unproved properties $ 4,578
Proved properties
Exploration costs 3,831
Development costs 382,995
Total costs incurred $ 391,404
Reserve summary (MBoe)
Balance-December 31, 2013 114,661
Extensions and discoveries 43,247
Production (1) (5,281 )
Revisions to previous estimates (6,379 )
Balance-December 31, 2014 146,248
Finding and development costs ($/Boe)
All-in F&D cost $ 10.62
Drill-bit F&D cost $ 8.94
Reserve replacement ratio
Drill-bit 819 %
(Extensions and discoveries / Production)

(1) Production includes 1,390 MMcf related to field fuel.

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, 2014 and 2013 (in thousands).

Liquidity at

December 31,

2014 2013
Borrowing base $ 450,000 $ 350,000
Cash and cash equivalents 432 58,761
Credit facility (150,000 )
Outstanding letters of credit (325 ) (325 )
Liquidity $ 300,107 $ 408,436

Long-Term Debt-to-Capital

Long-term debt-to-capital ratio is calculated by dividing long-term debt (GAAP) by the sum of total stockholders’ equity (GAAP) and long-term debt (GAAP). We use the long-term debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio has limitations. This ratio can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the ratio on a company’s financial statements. This ratio is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

The table below summarizes our long-term debt-to-capital ratio at December 31, 2014 and 2013 (in thousands).

Long-Term Debt-to-Capital at

December 31,

2014 2013
Long-term debt (1) $ 400,000 $ 250,000
Total stockholders’ equity 774,327 710,495
$ 1,174,327 $ 960,495
Long-term debt-to-capital 34.1 % 26.0 %
(1)

Long-term debt at December 31, 2014, is comprised of $250 million in 7% senior notes and $150 million in outstanding borrowings under our senior secured credit facility. Long-term debt at December 31, 2013, is comprised of $250 million in 7% senior notes.

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