Approach Resources Inc. Reports Fourth Quarter and Full-Year 2013 Results and 2013 Proved Reserves

Approach Resources Inc. (NASDAQ: AREX) today reported results for fourth quarter and full-year 2013 and estimated 2013 proved reserves.

Fourth Quarter 2013 Highlights

• Production was 11.3 MBoe/d, a 33% increase over the prior-year quarter
• Revenues were $58.6 million, a 66% increase over the prior-year quarter
• Net income was $64.3 million, or $1.65 per diluted share
• Adjusted net income was $8 million, or $0.20 per diluted share
• EBITDAX was a quarterly record of $41.1 million, or $1.05 per diluted share, and up 99% over the prior-year quarter

Full-Year 2013 Highlights

• Production was 9.4 MBoe/d, a 19% increase over the prior year
• Revenues were $181.3 million, a 41% increase over the prior year
• Net income was $72.3 million, or $1.85 per diluted share
• Adjusted net income was $18 million, or $0.46 per diluted share
• EBITDAX was an annual record of $127.8 million, or $3.28 per diluted share, and up 54% over the prior year

2013 Proved Reserves Highlights

• Year-end 2013 proved reserves were 114.7 MMBoe, a 20% increase over year-end 2012 proved reserves
• PV-10 was $1.1 billion, a 36% increase
• Reserve replacement ratio of 776%
• Drill-bit finding and development cost of $10.63 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 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 President and Chief Executive officer, commented, “Our fourth quarter and full-year 2013 results demonstrate significant progress in transitioning Approach’s strategy from drilling vertical gas wells to leading the horizontal development of the oil-rich, multi-zone Wolfcamp shale. Since 2011, when we began drilling horizontal Wolfcamp wells, we have tripled oil production, increased oil reserves by more than 2.5 times and increased our horizontal Wolfcamp reserves by five times. We believe this substantial growth underscores the future potential from the horizontal Wolfcamp shale oil play.

“We also generated substantial margin improvement due to our oil production growth and lower cost structure. In addition, we made consistent strides against our horizontal well cost target in 2013. We are capturing many cost-saving benefits and efficiencies from our field infrastructure and recycling systems, which are contributing to our operational momentum as we begin 2014. We also advanced delineation of the Wolfcamp C bench and our understanding of stacked wellbore development in 2013. We now consider the Wolfcamp C bench in full development with our recent three-well pad completion, which also supports our field development outlook for the horizontal Wolfcamp play.”

Fourth Quarter 2013 Results

Production for fourth quarter 2013 totaled 1,041 MBoe (11.3 MBoe/d), made up of 46% oil, 26% NGLs and 28% natural gas. Average realized commodity prices for fourth quarter 2013, before the effect of commodity derivatives, were $91.34 per Bbl of oil, $31.41 per Bbl of NGLs and $3.77 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $56.46 per Boe for fourth quarter 2013.

Net income for fourth quarter 2013 was $64.3 million, or $1.65 per diluted share, on revenues of $58.6 million. During fourth quarter 2013, Approach, together with our partner in Wildcat Permian Services LLC (“Wildcat”), completed the sale of all of the equity interests of Wildcat for a purchase price of $210 million. Wildcat owned and operated an oil pipeline system in Crockett and Reagan Counties, Texas. Net income for fourth quarter 2013 included a pre-tax gain of $90.7 million related to the sale of our interest in the Wildcat oil pipeline, subject to normal post-closing adjustments.

Net income for fourth quarter 2013 also included an unrealized loss on commodity derivatives of $1.3 million and a realized gain on commodity derivatives of $0.2 million. Excluding the unrealized loss on commodity derivatives, gain on the sale of our interest in Wildcat and related income taxes, adjusted net income (non-GAAP) for fourth quarter 2013 was $8 million, or $0.20 per diluted share. EBITDAX (non-GAAP) for fourth quarter 2013 was $41.1 million, or $1.05 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 $5.19 per Boe. Production and ad valorem taxes averaged $3.89 per Boe, or 6.9% of oil, NGL and gas sales. Exploration costs were $0.22 per Boe. General and administrative costs averaged $8.37 per Boe. Depletion, depreciation and amortization expense averaged $21.14 per Boe. Interest expense totaled $5.2 million.

Full-Year 2013 Results

Production for 2013 totaled 3,424 MBoe (9.4 MBoe/d), made up of 42% oil, 28% NGLs and 30% natural gas. Average realized commodity prices for 2013, before the effect of commodity derivatives, were $90.70 per Bbl of oil, $29.57 per Bbl of NGLs and $3.60 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $52.64 per Boe for 2013.

Net income for 2013 was $72.3 million, or $1.85 per diluted share, on revenues of $181.3 million. Net income for 2013 included an unrealized loss on commodity derivatives of $4.6 million, a realized loss on commodity derivatives of $1 million and a gain on the sale of our interest in Wildcat of $90.7 million. Excluding the unrealized loss on commodity derivatives, gain on the sale of our interest in Wildcat and related income taxes, adjusted net income (non-GAAP) for 2013 was $18 million, or $0.46 per diluted share. EBITDAX (non-GAAP) for 2013 was $127.8 million, or $3.28 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 $5.59 per Boe. Production and ad valorem taxes averaged $3.75 per Boe, or 7.1% of oil, NGL and gas sales. Exploration costs were $0.65 per Boe. General and administrative costs averaged $7.75 per Boe. Depletion, depreciation and amortization expense averaged $22.48 per Boe. Interest expense totaled $14.1 million.

Operations Update

During fourth quarter 2013, we drilled 15 horizontal wells and completed 14 horizontal wells. During 2013, we drilled a total of 45 horizontal wells and completed 40 horizontal wells. At December 31, 2013, we had nine horizontal wells waiting on completion. The average initial 24-hour rate for wells completed during fourth quarter 2013 was 766 Boe/d (64% oil), excluding one short-lateral horizontal well.

During fourth quarter 2013, we completed a three-well, multi-bench pad in central Project Pangea. The pad includes two Wolfcamp B bench wells, the Baker B 232HB (6,500 feet lateral) and the Baker B 238HB (6,902 feet lateral), and a Wolfcamp C bench well, the Baker B 234HC (6,132 feet lateral), spaced approximately 660 feet apart in the same bench and approximately 540 feet apart in the adjacent bench. The Wolfcamp C bench well flowed at an initial 24-hour rate of 970 Boe/d (81% oil). The Wolfcamp B bench wells flowed at initial 24-hour rates of 928 Boe/d (70% oil) and 843 Boe/d (49% oil), respectively.

2013 Estimated Proved Reserves and Costs Incurred

Year-end 2013 proved reserves totaled 114.7 MMBoe, up 20% from year-end 2012 proved reserves of 95.5 MMBoe. Our proved oil reserves increased 24% to 46.1 MMBbls, compared to year-end 2012 proved oil reserves of 37.3 MMBbls. Year-end 2013 proved reserves were 40% oil, 29% NGLs and 31% natural gas, compared to 39% oil, 30% NGLs and 31% natural gas at year-end 2012.

Proved developed reserves represent approximately 39% of total year-end 2013 proved reserves, up from 34% at year-end 2012. At December 31, 2013, 99.9% of our proved reserves were located in our core operating area in the southern Midland Basin.

The increase in year-end 2013 estimated proved reserves is primarily a result of our horizontal development project in the Wolfcamp shale oil play. Year-end 2013 estimated proved reserves included 81.6 MMBoe attributable to the horizontal Wolfcamp shale play, compared to 53.8 MMBoe at year-end 2012, representing a 52% increase.

The table below summarizes our estimated proved reserves attributable to the horizontal Wolfcamp shale oil play, compared to our estimated proved reserves attributable to vertical development for the years ended December 31, 2013, 2012 and 2011.

		Proved Reserves (MBoe)
		2013		2012		2011
Horizontal Wolfcamp
Proved developed		23,520		10,439		3,362
Proved undeveloped		58,073		43,342		13,337
Total		81,593		53,781		16,699
Percent of total proved reserves		71%		56%		22%
Other Vertical
Proved developed		21,669		22,336		30,249
Proved undeveloped		11,399		19,362		30,027
Total		33,068		41,698		60,276
Percent of total proved reserves		29%		44%		78%
Total proved reserves		114,661		95,479		76,975

During 2013, we recorded downward revisions totaling 4.7 MMBoe. Revisions included the reclassification of 7.8 MMBoe of proved undeveloped reserves to probable undeveloped, partially offset by 3.1 MMBoe of positive revisions attributable to natural gas that will be produced and used as field fuel. The proved undeveloped reserves reclassified as probable undeveloped are attributable to vertical Canyon locations in Project Pangea that we do not plan to drill within five years from their initial booking.

The following table summarizes the changes in our estimated proved reserves during 2013.

		Oil (MBbl)			NGLs (MBbl)			Natural Gas (MMcf)			Total (MBoe)
Balance – December 31, 2012		37,252			29,100			174,760			95,479
Extensions and discoveries		14,252			6,531			38,993			27,282
Acquisition		62			14			197			109
Production (1)		(1,444	)		(951	)		(6,737	)		(3,517	)
Revisions		(4,055	)		(2,102	)		8,789			(4,692	)
Balance – December 31, 2013		46,067			32,593			216,002			114,661
(1) Production includes 560 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, 2013, was $676.3 million. The PV-10, or pre-tax present value of our proved reserves discounted at 10%, of our proved reserves at December 31, 2013,was $1.1 billion, compared to $830.9 million at year-end 2012. The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2013 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 2013 proved reserves and PV-10 were prepared using $97.28 per Bbl of oil, $30.16 per Bbl of NGLs and $3.66 per MMBtu of natural gas.

Preliminary, unaudited costs incurred during 2013 totaled $297 million and included $250 million for drilling and completion activities, $38 million for pipeline and infrastructure projects, $8.3 million for property and acreage acquisitions and lease extensions and $0.7 million for 3-D seismic data acquisition.

Liquidity Update

At December 31, 2013, we had a $500 million revolving credit facility with a $350 million borrowing base and no outstanding borrowings. At December 31, 2013, our liquidity and long-term debt-to-capital ratio were approximately $408.4 million and 26%, respectively.

Conference Call Information and Summary Presentation

The Company will host a conference call on Tuesday, February 25, 2014, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss financial and operational results for the fourth quarter and full-year 2013. 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 / 93847436

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

Dial in:					(855) 859-2056
Passcode:					93847436

In addition, a fourth quarter and full-year 2013 summary presentation is 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 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,
		2013				2012				2013				2012
Revenues (in thousands):
Oil		$	43,421			$	23,398			$	130,971			$	82,087
NGLs			8,421				7,014				28,103				30,811
Gas			6,723				4,897				22,228				15,994
Total oil, NGL and gas sales		58,565				35,309				181,302				128,892
Realized gain (loss) on commodity derivatives		199				(408		)		(1,048		)		(108		)
Total oil, NGL and gas sales including derivative impact		$	58,764			$	34,901			$	180,254			$	128,784
Production:
Oil (MBbls)		475				299				1,444				969
NGLs (MBbls)		268				232				951				904
Gas (MMcf)		1,784				1,522				6,177				6,089
Total (MBoe)		1,041				784				3,424				2,888
Total (MBoe/d)		11.3				8.5				9.4				7.9
Average prices:
Oil (per Bbl)		$	91.34			$	78.27			$	90.70			$	84.70
NGLs (per Bbl)			31.41				30.27				29.57				34.09
Gas (per Mcf)			3.77				3.22				3.60				2.63
Total (per Boe)		$	56.27			$	45.02			$	52.95			$	44.63
Realized gain (loss) on commodity derivatives (per Boe)		0.19				(0.52		)		(0.31		)		(0.03		)
Total including derivative impact (per Boe)		$	56.46			$	44.50			$	52.64			$	44.60
Costs and expenses (per Boe):
Lease operating		$	5.19			$	7.29			$	5.59			$	6.58
Production and ad valorem taxes		3.89				3.12				3.75				3.20
Exploration		0.22				2.72				0.65				1.58
General and administrative		8.37				10.79				7.75				8.62
Depletion, depreciation and amortization		21.14				22.99				22.48				20.91

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,
		2013			2012			2013			2012
REVENUES:
Oil, NGL and gas sales		$	58,565		$	35,309		$	181,302		$	128,892
EXPENSES:
Lease operating			5,406			5,716			19,152			19,002
Production and ad valorem taxes			4,049			2,448			12,840			9,255
Exploration			228			2,131			2,238			4,550
General and administrative			8,714			8,455			26,524			24,903
Depletion, depreciation and amortization			22,005			18,027			76,956			60,381
Total expenses			40,402			36,777			137,710			118,091
OPERATING INCOME (LOSS)			18,163			(1,468	)		43,592			10,801
OTHER:
Interest expense, net			(5,225	)		(926	)		(14,084	)		(4,737	)
Equity in (losses) earnings of investee			(4	)		(108	)		156			(108	)
Gain on sale of equity method investment			90,743			—			90,743			—
Realized gain (loss) on commodity derivatives			199			(408	)		(1,048	)		(108	)
Unrealized (loss) gain on commodity derivatives			(1,348	)		1,292			(4,596	)		3,874
INCOME (LOSS) BEFORE INCOME TAX PROVISION (BENEFIT)			102,528			(1,618	)		114,763			9,722
INCOME TAX PROVISION (BENEFIT):
Current			429			—			429			—
Deferred			37,778			(781	)		42,078			3,338
NET INCOME (LOSS)		$	64,321		$	(837	)	$	72,256		$	6,384
EARNINGS (LOSS) PER SHARE:
Basic		$	1.65		$	(0.02	)	$	1.85		$	0.18
Diluted		$	1.65		$	(0.02	)	$	1.85		$	0.18
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic			39,047,495			38,862,091			38,997,815			34,965,182
Diluted			39,067,553			38,862,091			39,019,149			35,030,323

UNAUDITED SELECTED FINANCIAL DATA
Unaudited Consolidated Balance Sheet Data			December 31,
(in thousands)			2013			2012
Cash and cash equivalents			$	58,761		$	767
Restricted cash				7,350			—
Other current assets				24,302			14,889
Property and equipment, net, successful efforts method				1,047,030			828,467
Equity method investment				—			9,892
Other assets				8,041			1,724
Total assets			$	1,145,484		$	855,739
Current liabilities			$	84,441		$	60,247
Long-term debt (1)				250,000			106,000
Other long-term liabilities				100,548			56,024
Stockholders’ equity				710,495			633,468
Total liabilities and stockholders’ equity			$	1,145,484		$	855,739

(1)

Long-term debt at December 31, 2013, is comprised of $250 million in 7% senior notes. Long-term debt at December 31, 2012, is comprised of borrowings under our credit facility.

Unaudited Consolidated Cash Flow Data		Twelve Months Ended December 31,
(in thousands)		2013			2012
Net cash provided (used) by:
Operating activities		$	125,580		$	90,585
Investing activities		$	(203,397	)	$	(307,414	)
Financing activities		$	135,811		$	217,295

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 (loss) to net income (loss) for the three and twelve months ended December 31, 2013 and 2012 (in thousands, except per-share amounts).

		Three Months Ended December 31,								Twelve Months Ended December 31,
		2013				2012				2013				2012
Net income (loss)		$	64,321			$	(837	)		$	72,256			$	6,384
Adjustments for certain items:
Unrealized loss (gain) on commodity derivatives			1,348				(1,292	)			4,596				(3,874	)
Gain on sale of equity method investment			(90,743	)			—				(90,743	)			—
Related income tax effect			33,076				439				31,874				1,317
Adjusted net income (loss)		$	8,002			$	(1,690	)		$	17,983			$	3,827
Adjusted net income (loss) per diluted share		$	0.20			$	(0.04	)		$	0.46			$	0.11

EBITDAX

We define EBITDAX as net income (loss), 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 loss (gain) 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 (loss) for the three and twelve months ended December 31, 2013 and 2012 (in thousands, except per-share amounts).

		Three Months Ended December 31,								Twelve Months Ended December 31,
		2013				2012				2013				2012
Net income (loss)		$	64,321			$	(837	)		$	72,256			$	6,384
Exploration			228				2,131				2,238				4,550
Gain on sale of equity method investment			(90,743	)			—				(90,743	)			—
Depletion, depreciation and amortization			22,005				18,027				76,956				60,381
Share-based compensation			512				2,472				5,901				7,465
Unrealized loss (gain) on commodity derivatives			1,348				(1,292	)			4,596				(3,874	)
Interest expense, net			5,225				926				14,084				4,737
Income tax provision (benefit)			38,207				(781	)			42,507				3,338
EBITDAX		$	41,103			$	20,646			$	127,795			$	82,981
EBITDAX per diluted share		$	1.05			$	0.53			$	3.28			$	2.37

PV-10

The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $1.1 billion at December 31, 2013, and was calculated based on the first-of-the-month, twelve-month average prices for oil, NGLs and gas, of $97.28 per Bbl of oil, $30.16 per Bbl of NGLs and $3.66 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, 2013
PV-10		$	1,132
Less income taxes:
Undiscounted future income taxes			(919	)
10% discount factor			463
Future discounted income taxes			(456	)
Standardized measure of discounted future net cash flows		$	676

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 March 3, 2014. 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 2013 to the information required by paragraphs 11 and 21 of ASC 932-235:

Cost summary (in thousands)
Property acquisition costs
Unproved properties		$	5,857
Proved properties			1,000
Exploration costs			2,238
Development costs			287,898
Total costs incurred		$	296,993
Reserve summary (MBoe)
Balance―December 31, 2012			95,479
Extensions and discoveries			27,282
Acquisition			109
Production (1)			(3,517	)
Revisions to previous estimates			(4,692	)
Balance―December 31, 2013			114,661
Finding and development costs ($/Boe)
All-in F&D cost		$	13.08
Drill-bit F&D cost		$	10.63
Reserve replacement ratio
Drill-bit			776	%
(Extensions and discoveries / Production)
(1) Production includes 560 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, 2013 and 2012 (in thousands).

		Liquidity at December 31,
		2013				2012
Borrowing base		$	350,000			$	280,000
Cash and cash equivalents			58,761				767
Outstanding letters of credit			(325	)			(325	)
Credit facility			—				(106,000	)
Liquidity		$	408,436			$	174,442

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, 2013 and 2012 (in thousands).

		Long-Term Debt-to-Capital at December 31,
		2013				2012
Long-term debt (1)		$	250,000			$	106,000
Total stockholders’ equity			710,495				633,468
		$	960,495			$	739,468
Long-term debt-to-capital			26.0	%			14.3	%

(1)

Long-term debt at December 31, 2013, is comprised of $250 million in 7% senior notes. Long-term debt at December 31, 2012, is comprised of borrowings under our credit facility.