Rex Energy 8-K Rex Energy Announces Interim 2012 Proved Reserves, 2013 Capital Budget and Guidance

Exhibit 99.3

ITEM 6. SELECTED FINANCIAL DATA

Summary Financial Data

The following table shows selected consolidated and combined financial data of Rex Energy Corporation and the Predecessor Companies for each of the periods indicated. The historical consolidated financial data has been prepared for Rex Energy Corporation for the years ended December 31, 2011, 2010, 2009 and 2008. The historical combined financial data has been prepared for the Predecessor Companies for the year ended December 31, 2007. The historical consolidated and combined financial statements for all years presented are derived from the historical audited financial data of Rex Energy Corporation and the Predecessor Companies. All material intercompany balances and transactions have been eliminated. Because each of the Predecessor Companies was taxed as a partnership for each of the periods indicated for federal and state income tax purposes, the following statements make no provision for income taxes for the seven month period ended July 31, 2007. Provision for income tax is presented for the five month period ended December 31, 2007. This information should be read in conjunction with Exhibit 99.2 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our Consolidated Financial Statements and related notes as of December 31, 2011 and 2010 and for each of the years ended December 31, 2011, 2010 and 2009, included elsewhere in this report. These selected combined historical financial results may not be indicative of our future financial or operating results.

The following tables include the non-GAAP financial measure of EBITDAX. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures” section.

	Rex Energy Corporation Consolidated		Rex Energy Corporation Consolidated		Rex Energy Corporation Consolidated		Rex Energy Corporation Consolidated		Rex Energy Corporation Consolidated & Combined Predecessor Companies
	Year Ended December 31, ($ in Thousands, Except per Share Data)
	2011		2010		2009		2008		2007
Statement of Operations Data:
Operating Revenue:
Oil, Natural Gas and NGL Sales	$	111,879	$	67,224	$	48,534	$	84,013	$	58,133
Field Services Revenue		2,518		1,366		—		—		—
Other Revenue		209		173		157		123		101
Total Operating Revenue		114,606		68,763		48,691		84,136		58,234

Operating Expenses:
Production and Lease Operating Expense		33,116			24,656			22,157			26,511			22,361
General and Administrative Expense		23,636			17,141			15,858			15,185			7,793
(Gain) Loss on Disposal of Assets		502			(16,395	)		427			6,468			(12	)
Impairment Expense		14,631			8,863			1,625			71,349			—
Exploration Expense		2,507			2,578			2,080			3,261			1,238
Depreciation, Depletion, Amortization & Accretion		28,361			21,806			25,205			37,904			17,804
Field Services Operating Expenses		1,750			1,188			—			—			—
Other Operating Expenses (Income)		819			153			—			—			—
Total Operating Expense		105,322			59,990			67,352			160,678			49,184
Income (Loss) from Operations		9,284			8,773			(18,661	)		(76,542	)		9,050
Other Income (Expense):
Interest Income		10			68			7			328			15
Interest Expense		(2,019	)		(1,070	)		(833	)		(1,091	)		(5,665	)
Gain (Loss) on Derivatives, Net		18,916			6,055			(7,913	)		27,328			(32,429	)
Other Income (Expense)		79			(321	)		(161	)		(114	)		(6	)
Gain (Loss) on Equity Method Investments		81			(200	)		(9	)		(54	)		(12	)
Total Other Income (Expense)		17,067			4,532			(8,909	)		26,397			(38,097	)
Income (Loss) from Continuing Operations Before Income Tax		26,351			13,305			(27,570	)		(50,145	)		(29,047	)
Income Tax Benefit (Expense)		(8,270	)		(5,500	)		11,002			9,167			7,365
Income (Loss) from Continuing Operations		18,081			7,805			(16,568	)		(40,978	)		(21,682	)
Income (Loss) from Discontinued Operations, Net of Income Taxes		(33,457	)		(2,022	)		323			(7,704	)		(681	)
Net Income (Loss)		(15,376	)		5,783			(16,245	)		(48,682	)		(22,363	)
Net Income (Loss) Attributable to Noncontrolling Interests		(7	)		(253	)		(12	)		—			6,152
Net Income (Loss) Attributable to Rex Energy	$	(15,369	)	$	6,036		$	(16,233	)	$	(48,682	)	$	(16,211	)

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Earnings per Common Share1
Basic—income (loss) from continuing operations attributable to Rex common shareholders	$	0.41		$	0.18		$	(0.45	)	$	(1.18	)	$	(0.73	)
Basic—income (loss) from discontinued operations attributable to Rex common shareholders		(0.76	)		(0.05	)		0.01			(0.22	)		(0.02	)
Basic—net income (loss) attributable to Rex common shareholders	$	(0.35	)	$	0.13		$	(0.44	)	$	(1.40	)	$	(0.75	)
Basic—weighted average shares of common stock outstanding		43,930			43,281			36,806			34,595			30,795
Diluted—income (loss) from continuing operations attributable to Rex common shareholders	$	0.41		$	0.18		$	(0.45	)	$	(1.18	)	$	(0.73	)
Diluted—net income (loss) from discontinued operations attributable to Rex common shareholders		(0.76	)		(0.05	)		0.01			(0.22	)		(0.02	)
Diluted—net income (loss) attributable to Rex common shareholders	$	(0.35	)	$	0.13		$	(0.44	)	$	(1.40	)	$	(0.75	)
Diluted—weighted average shares of common stock outstanding		44,476			43,670			36,806			34,595			30,795

(1) Earnings per common share for 2007 represents a loss from continuing operations of $11,304 and a gain from discontinued operations of $664 for the 5 month period ended December 31, 2007.

	Year Ended December 31, ($ in Thousands)
	2011			2010			2009			2008			2007
Other Financial Data:
EBITDAX from Continuing Operations	$	65,366		$	27,091		$	22,493		$	29,119		$	28,225
Cash Flow Data:
Cash provided by operating activities		64,507			34,102			20,774			32,428			17,555
Cash used by investing activities		(276,574	)		(94,921	)		(30,061	)		(127,800	)		(40,102	)
Cash provided by financing activities		212,855			66,245			7,823			101,333			23,032
Balance Sheet Data:
Cash and Cash Equivalents		11,796			11,008			5,582			7,046			1,085
Property and Equipment (net of Accumulated Depreciation)		480,244			275,923			275,261			249,858			191,171
Total Assets		601,551			407,085			304,950			302,006			268,264
Current Liabilities, including current portion of Long-Term Debt		63,366			63,337			32,411			17,353			20,612

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Long-Term Debt, net of current maturities	225,138	10,120	23,049	15,000	27,207
Total Liabilities	309,277	102,409	84,753	70,158	103,827
Noncontrolling Interests	275	295	3,343	—	—
Owners’ Equity	292,274	304,676	220,197	231,848	164,437

Summary Operating and Reserve Data

The following table summarizes our operating and reserve data as of and for each of the periods indicated for continuing operations. The table includes the non-GAAP financial measure of PV-10. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flow, its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures” below.

	2011		2010		2009
Production
Oil (Bbls)		694,452		691,574		720,010
Natural gas (Mcf)		8,912,250		3,088,598		1,510,500
NGLs (Bbls)		190,151		25,559		7,750
Mcf equivalent (Mcfe)		14,219,868		7,391,396		5,877,060
Oil and natural gas sales (a)
Oil sales	$	63,515	$	52,577	$	41,881
Natural gas sales	$	38,161	$	13,789	$	6,460
NGLs sales	$	10,203	$	858	$	193
Total	$	111,879	$	67,224	$	48,534
Average sales price (a)
Oil ($ per Bbl)	$	91.46	$	76.03	$	58.17
Natural gas ($ per Mcf)	$	4.28	$	4.46	$	4.28
NGLs ($ per Bbl)	$	53.66	$	33.60	$	24.90
Mcf equivalent ($ per Mcfe)	$	7.87	$	9.10	$	8.26
Average production cost
Mcf equivalent ($ per Mcfe)	$	2.33	$	3.34	$	3.77

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Estimated proved reserves (b)
Bcf equivalent (Bcfe)		366.2			201.7			125.2
% Oil		13	%		24	%		49	%
% Proved producing		45	%		38	%		51	%
PV-10 (millions)	$	539.6		$	269.4		$	190.5
Standardized measure (millions)	$	413.9		$	188.1		$	144.4

(a) Information excludes the impact of our financial derivative activities.

(b) The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our financial derivative activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The estimated present value of estimated proved reserves does not give effect to indirect expenses such as debt service and future income tax expense, asset retirement obligations, or to depletion, depreciation and amortization. The reserve information shown is estimated. The certainty of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation, and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

Non-GAAP Financial Measures

We include in this report our calculations of EBITDAX and PV-10, which are non-GAAP financial measures. Below, we provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measure as calculated and presented in accordance with GAAP.

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized losses from financial derivatives, exploration expenses and other non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of our financial statements, such as our commercial bank lenders, to analyze such things as:

• Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure;

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• The financial performance of our assets and valuation of the entity without regard to financing methods, capital structure or historical cost basis;

• Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and

• The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring our performance, nor used as an exclusive measure of cash flow, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and we believe this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed our EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.

We believe EBITDAX assists our lenders and investors in comparing a company’s performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Additionally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.

To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.

The following table presents a reconciliation of our net income to our EBITDAX for each of the periods presented:

For purposes of consistency with current calculations, we have revised certain amounts relating to prior period EBITDAX.

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	Year Ended December 31,															Nine Months Ended September 30,
($ in thousands)	2007			2008			2009			2010			2011			2011			2012
Net Income (Loss) From Continuing Operations	$	(21,682	)	$	(40,978	)	$	(16,568	)	$	7,805		$	18,081		$	16,930		$	58,281
Net (Income) Loss Attributable to Noncontrolling Interests		6,152			—			12			253			7			14			(516	)
Income (Loss) From Continuing Operations Attributable to Rex Energy		(15,530	)		(40,978	)		(16,556	)		8,058			18,088			16,944			57,765
Add Back Retroactive Portion of New Pennsylvania Impact Fee																	—			2,809
Add Back Depletion, Depreciation, Amortization and Accretion		17,804			37,904			25,205			21,806			28,361			19,641			33,082
Add Back Non-Cash Compensation Expense		211			2,990			1,557			907			1,601			1,295			2,147
Add Back Interest Expense (1)		5,631			1,014			1,595			1,713			2,009			1,024			3,655
Add Back Impairment Expense		—			71,349			1,625			8,863			14,631			2,928			3,357
Add Back Exploration Expense		1,238			3,261			2,080			2,578			2,507			2,203			3,511
Add Back Less Loss (Gain) on Disposal of Assets		(12	)		6,468			427			(16,395	)		502			464			(92,128	)
Add Back Less Unrealized Loss (Gain) on Financial Derivatives		26,250			(43,746	)		17,558			(5,960	)		(12,704	)		(8,972	)		8,167
Less Non-Cash Portion of Noncontrolling Interests		—			—			(2	)		(119	)		(157	)		(139	)		(64	)
Add Back (Less) Non-Cash Portion of Equity Method Investments		(2	)		24			6			140			2,258			1,118			4,294
Add Back (Less) Income Tax Expense (Benefit)		(7,365	)		(9,167	)		(11,002	)		5,500			8,270			8,207			35,768
EBITDAX from Continuing Operations		28,225			29,119			22,493			27,091			65,366			44,713			62,363
Net Income (Loss) From Discontinued Operations	$	(681	)	$	(7,704	)	$	323		$	(2,022	)	$	(33,457	)	$	(29,197	)	$	(8,662	)
Add Back Depletion, Depreciation, Amortization and Accretion		1,819			1,565			—			1			85			77			—
Add (Less) Back Non-Cash Compensation Expense (Income)		—			—			—			7			24			46			(31	)
Add Back Interest Expense		—			—			—			—			1			—			—
Add Back Impairment Expense		—			8,729			—			—			13,176			11,255			12,951
Add Back Exploration Expense		1,710			2,198			—			2,664			33,812			31,562			810
Add Back (Less) Loss (Gain) on Disposal of Assets		(173	)		41			—			—			—			—			148
Add Back (Less) Unrealized Loss (Gain) on Financial Derivatives		—			558			(558	)		—			—			—			—
Add Back (Less) Income Tax Expense (Benefit)		348			(1,736	)		288			(1,440	)		(15,302	)		(15,073	)		(6,064	)
EBITDAX from Discontinued Operations		3,023			3,651			53			(790	)		(1,661	)		(1,330	)		(848	)
EBITDAX	$	31,248		$	32,770		$	22,546		$	26,301		$	63,705		$	43,383		$	61,515

(1) Includes realized settlements on interest rate swap.

PV-10

The following table shows the reconciliation of 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 represents our estimate of the present value, discounted at 10% per annum, of estimated future cash flows of our estimated proved reserves before income tax and asset retirement obligations. Our estimated future cash flows as of December 31, 2009, 2010 and 2011 were determined by using reserve quantities of estimated proved reserves and the periods in which they are expected to be

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developed and produced based on the prevailing economic conditions. The estimated future production for the years ended December 31, 2009, 2010 and 2011, was priced based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December, without escalation, using $57.65 per Bbl, $76.03 per Bbl and $92.45 per Bbl of oil, respectively, and $3.866 per MMBtu, $ 4.567 per MMBtu and $4.545 per MMBtu of natural gas, respectively, as adjusted by lease for transportation fees and regional price differentials. NGLs were priced at $57.65 per Bbl, $31.71 per Bbl and $46.34 per Bbl for the years ended December 31, 2009, 2010 and 2011, respectively. Management believes that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural 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 our company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

	2011			2010			2009
Reconciliation of standardized measure to PV-10
PV-10	$	539.6		$	269.4		$	190.5
Add: Present value of future income tax discounted at 10%		(107.0	)		(64.1	)		(30.0	)
Add: Present value of future asset retirement obligations discounted at 10%		(18.7	)		(17.2	)		(16.1	)
Standardized measure of discounted future net cash flows	$	413.9		$	188.1		$	144.4

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with “Item 6. Selected Financial Data” and the Consolidated Financial Statements and related notes included elsewhere in this report. This discussion contains forward-looking statements reflecting our current expectations and estimates, and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” appearing elsewhere in this report. All financial and operating data presented are the results of continuing operations unless otherwise noted.

Overview of Our Business

We are an independent oil and gas company operating in the Appalachian Basin and the Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale drilling projects and Utica Shale exploration. In the Illinois Basin, in addition to our developmental conventional oil drilling, we are focused on the implementation of enhanced oil recovery on our properties. We pursue a balanced growth strategy of pursuing our higher potential exploration drilling prospects and actively seeking to acquire complementary oil and natural gas properties.

We are headquartered in State College, Pennsylvania, and have regional offices in Bridgeport, Illinois, Butler, Pennsylvania, Seven Fields, Pennsylvania and Carrolton, Ohio.

We divide our operations into two principal business segments, exploration and production and field services.

Exploration and Production Segment

Our exploration and production segment engages in the exploration, acquisition, development and production of oil, natural gas and natural gas liquids. We generally evaluate the performance of our exploration and production segment based on production volumes and net income (loss) from continuing operations, before income taxes. Our financial results from exploration and production depend upon many factors, particularly the price of oil and gas. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, refinery or pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success.

During 2011, we increased our proved reserves base by approximately 81.6%, from 201.7 Bcfe at December 31, 2010. The primary contributing factor to this increase was our continued drilling success in

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the Appalachian Basin, where we placed into service 51.0 gross (25.9 net) wells which also resulted in an increase in production of 92.4%. Amidst our successful drilling endeavors, we successfully drilled two successful test wells, one to the Utica Shale and one to the Burkett Shale, solidifying our belief that there are multiple producing zones underlying our acreage in Butler County, Pennsylvania. We continued to increase our acreage position in the Appalachian Basin during 2011, ending the year with approximately 162,200 gross (93,900 net) acres under leasehold, which includes approximately 15,000 gross acres in Ohio that we believe to be prospective for the liquids-rich portion of the Utica Shale. As of December 31, 2011, our acreage holdings prospective for liquids-rich production accounted for approximately 82.6% of our total net acreage. Through our acreage holdings and successful drilling operations we have been able to expand our available drilling inventory, which now includes 192.9 Bcfe in proved undeveloped reserves covering 90.0 gross proved undeveloped drilling locations. To prepare for our future growth, we have entered into various gathering, processing and sales agreements to ensure market capacity for our projected production.

In 2010, we entered into a joint venture agreement with Sumitomo. In accordance with the agreement, we sold a 15% non-operated interest in our Butler County, Pennsylvania project area and Sumitomo also agreed to lease an additional 9,000 acres in this project area. The leasing arrangement was concluded during 2011; consequently, the ownership percentages in the project area are approximately 70% to us and 30% to Sumitomo. In addition to our Butler County, Pennsylvania project area, we also sold a 20% non-operated interest in our joint venture area with Williams (discussed below) and a 50% non-operated interest in undeveloped acreage in Fayette and Centre Counties, Pennsylvania. At closing, we received approximately $99.5 million in cash, which included a reimbursement for leasing expenses incurred subsequent to the effective date of September 1, 2010, in the amount of $7.6 million, and a reimbursement for drilling related expenses incurred subsequent to the effective date in the amount of approximately $7.5 million. As a part of the joint venture agreement, Sumitomo agreed to pay 80% of our net drilling and completion expenses up to approximately $58.8 million. For additional information on the transaction with Sumitomo, see Note 4,Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements.

In 2009, we entered into a joint venture agreement with Williams. In accordance with the agreement, we sold a 50% working interest in certain oil and gas leases in Centre, Clearfield and Westmoreland Counties, Pennsylvania through a “drill-to-earn” structure. For Williams to earn its 50% interest they were required to bear 90% of all costs and expenses incurred in the drilling and completion of all wells jointly drilled until such time Williams had invested approximately $74.0 million (approximately $33.0 million on behalf of us and $41.0 million for Williams’ 50% share of the wells). As of December 31, 2010, Williams had completed its carry obligation and acquired their 50% working interest. Subsequent to the joint venture agreement with Sumitomo, the ownership percentages are approximately 50% to Williams, 40% to us and 10% to Sumitomo. For additional information on the transaction with Williams, see Note 4,Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements.

Field Services Segment

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Our field services segment operates and manages water sourcing, water transfer and water disposal services, primarily in the Appalachian Basin. We generally evaluate the performance of our field services segment based on net income (loss) from continuing operations, before income taxes. Our financial results from field services are largely contingent upon drilling and completion activities in the Appalachian Basin, particularly in regions where the Marcellus and Utica Shale plays are prominent. Our field services results are subject to similar economic risks as discussed for our exploration and production segment, such as commodity price risk, due to the relation to drilling and completion activity levels.

During 2011, we increased field services revenues by approximately 84.3%, from $1.4 million in 2010. Loss from continuing operations before income tax expense was approximately $1.1 million in 2011 as compared to $0.8 million in 2010. Our field services segment, which began operations in early 2010, owns and operates several water withdrawal points within the Commonwealth of Pennsylvania that we utilize to sell water to companies within the exploration and production industry for use in fracture stimulation activities. We also offer water transportation services via temporary or permanent pipelines and water processing services.

Source of Our Revenue

We generate our revenue primarily from the sale of crude oil to refining companies and natural gas to local distribution and pipeline companies. Our operating revenue before the effects of financial derivatives from these operations, and their relative percentages of our total revenue, consisted of the following:

	2011		% of Total			2010		% of Total			2009		% of Total
Sources of Revenue ($ in thousands):
Revenue from Oil Sales	$	63,515		55.4	%	$	52,577		76.5	%	$	41,881		86.0	%
Revenue from Natural Gas Sales		38,161		33.3	%		13,789		20.1	%		6,460		13.3	%
Revenue from NGL Sales		10,203		8.9	%		858		1.2	%		193		0.4	%
Revenue from Field Services		2,518		2.2	%		1,366		2.0	%		—
Other		209		0.2	%		173		0.2	%		157		0.3	%
Total	$	114,606		100.0	%	$	68,763		100.0	%	$	48,691		100.0	%

We have identified the impact of generally volatile commodity prices in the last several years as an important trend that we expect to affect our business in the future. If commodity prices increase, we would expect not only an increase in revenue, but also in the competitive environment for quality drilling prospects, qualified geological and technical personnel and oil field services, including rig availability. Increasing competition in these areas would likely result in higher costs in these areas, and could result in unavailability of drilling rigs, thus affecting the profitability of our future operations. We may not be able to compete successfully in the future with larger competitors in acquiring prospective reserves,

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developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. In the event of a declining commodity price environment, our revenues would decrease and we would anticipate that the cost of materials and services would decrease as well, although at a slower rate. Decreasing oil or natural gas prices may also make some of our prospects uneconomical to drill.

Principal Components of Our Cost Structure

Our operating and other expenses consist of the following:

• Production and Lease Operating Expenses. Day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include workovers, repairs to our oil and gas properties not covered by insurance, and various production taxes that are paid based upon rates set by federal, state, and local taxing authorities.

• General and Administrative Expense. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters and regional offices, costs of managing our production and development operations, audit and other professional fees, and legal compliance are included in general and administrative expense. General and administrative expense includes non-cash stock-based compensation expense as part of employee compensation.

• Exploration Expense. Geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory wells, also known as dry holes.

• Field Services Operating Expense. Project related expenses incurred in correlation with our Field Services segment. These expenses are largely variable in nature and fluctuate commensurate with our level of activity, particularly on water transfer and water disposal projects. These charges include wages and benefits, insurance, field supplies, rental equipment and materials.

• Interest. We typically finance a portion of our working capital requirements and acquisitions with borrowings under our senior credit facility. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We may continue to incur significant interest expense as we continue to grow.

• Depreciation, Depletion, Amortization and Accretion. The systematic expensing of the capital costs incurred to acquire, explore and develop natural gas and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities.

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• Income Taxes. We are subject to state and federal income taxes but are currently not in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). We do pay some state income taxes where our IDC deductions do not exceed our taxable income or where state income taxes are determined on another basis. Currently, all of our federal taxes are deferred; however, we have scheduled the timing of reversal of our deferred tax assets and believe we will use all of our net operating loss carryforwards prior to their expiration.

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements, which are viewed on a company-wide basis, include EBITDAX (a non-GAAP measure), lease operating expenses per Mcf equivalent (“Mcfe”), growth in our proved reserve base, and general and administrative expenses per Mcfe. The following table presents these metrics for continuing operations for each of the three years ended December 31, 2011, 2010 and 2009.

	Performance Measurements
	Years Ended December 31,
	2011		2010		2009
EBITDAX ($ in thousands)	$	65,366	$	27,091	$	22,493
Production Cost per Mcfe	$	2.33	$	3.34	$	3.77
Total Estimated Proved Reserves (Bcfe)		366.2		201.7		125.2
G&A per Mcfe	$	1.66	$	2.32	$	2.70

EBITDAX

“EBITDAX,” a non-GAAP measure, means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized losses from financial derivatives, exploration expenses and other non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of our financial statements, such as our commercial bank lenders, to analyze such things as:

• Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure;

• The financial performance of our assets and valuation of the entity, without regard to financing methods, capital structure or historical cost basis;

• Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and

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• The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures.”

Production Cost per Mcfe

Production costs are comprised of those expenses which are directly attributable to our producing oil and gas leases, including state and county production taxes, production related insurance, the cost of materials, maintenance, electricity, chemicals, gathering, processing, fuel and the wages of our field personnel. Our production costs per Mcfe are higher than those of many of our peers primarily because of the nature of our oil properties, many of which are mature waterflood properties. Our production cost per Mcfe produced in 2011 was $2.33 as compared to $3.34 in 2010 and $3.77 in 2009. As we continue to develop our non-proved properties, such as the Marcellus Shale, which have a lower operating cost, we believe this metric will continue to decrease on a per unit basis.

Growth in our Proved Reserve Base

We measure our ability to grow our estimated proved reserves over the amount of our total annual production. As we produce oil and gas attributable to our estimated proved reserves, our estimated proved reserves decrease each year by that amount of production. We attempt to replace these produced estimated proved reserves each year through the addition of new estimated proved reserves through our drilling and other property improvement projects and through acquisitions. Our estimated proved reserves have fluctuated since 2009, from 125.2 Bcfe at year end 2009 to 201.7 Bcfe at year end 2010 to 366.2 Bcfe at year end 2011. Our reserve replacement ratio for year end 2009 was approximately 410% based on total production for the year of 5.9 Bcfe and extensions, discoveries and other additions of 24.1 Bcfe. Our reserve replacement ratio for year end 2010 was approximately 1,559% based on total production for the year of 7.3 Bcfe, and extensions, discoveries and other additions of 98.2 Bcfe. Our reserve replacement ratio for year end 2011 was approximately 1,096% based on total production for the year of 14.2 Bcfe, and extensions, discoveries and other additions of 178.7 Bcfe.

Our estimated proved reserve base increased in 2011 when compared to 2010 predominately due to our successful drilling and exploration programs in the Marcellus Shale and the increase in oil prices used for the reserves determination. As of December 31, 2010, we removed all proved undeveloped locations related to our conventional drilling opportunities in the Illinois and Appalachian Basins from our proved reserve totals, which is in compliance with SEC rules requiring a high degree of confidence that the quantities related to proved undeveloped reserves will be recovered and they are scheduled to be drilled within the next five years. For 2011, our proved reserve base in the Marcellus Shale increased by approximately 112.8%, while our estimated proved reserves in the Illinois Basin increased by 0.5%.

General and Administrative Expenses per Mcfe

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Our general and administrative expenses include fees for well operating services, marketing, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our general and administrative expenses in relation to our production because these expenses have a direct impact on our profitability. In 2011 our general and administrative expenses per Mcfe produced decreased to $1.66 from $2.32 in 2010 and from $2.70 in 2009. As we continue to develop our non-proved properties, we believe this metric will continue to decrease on a per unit basis.

Results of Continuing Operations

General Overview

Operating revenue increased 66.7% for 2011 over 2010. This increase is primarily due to increased oil and gas production in each of our operating regions and higher oil and NGL prices, which were partially offset by lower natural gas prices. For 2011, total production increased 92.4% to 14,220 MMcfe from 7,391 MMcfe in 2010 due to the continued success of our drilling programs, primarily in the Marcellus Shale.

Operating expenses increased $45.3 million in 2011, or 75.6%, as compared to 2010. Operating expenses are primarily composed of production expenses, general and administrative expenses, gain (loss) on disposal of assets, exploration expenses, impairment of oil and gas properties, depreciation, depletion, amortization and accretion expenses (“DD&A”) and field service operating expenses. The increases in operating expense were primarily due to the growth of our operations, particularly in Butler County, Pennsylvania where we are required to process our gas prior to entry into the sales line. Also contributing to the increase were impairment expenses, which were approximately $5.8 million higher than in 2010 primarily due to the write-down of our conventional natural gas properties in the Appalachian Basin. Approximately $16.4 million of the increase was due to the gain on sale recognized as a result of the Sumitomo transaction in 2010.

Comparison of the Year Ended December 31, 2011 to the Year Ended December 31, 2010

Oil and gas revenue for the years ended December 31, 2011 and 2010 is summarized in the following table:

	December 31,
	2011			2010			Change		%
Oil and Gas Revenue ($ in thousands):
Oil sales revenue	$	63,515		$	52,577		$	10,938		20.8	%
Oil derivatives realized		(670	)		(3,861	)		3,191		82.6	%

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Total oil revenue and derivatives realized	$	62,845	$	48,716	$	14,129		29.0	%
Gas sales revenue	$	38,161	$	13,789	$	24,372		176.7	%
Gas derivatives realized		6,882		4,667		2,215		47.5	%
Total gas revenue and derivatives realized	$	45,043	$	18,456	$	26,587		144.1	%
Total NGL revenue	$	10,203	$	858	$	9,345		1,089.2	%
Consolidated sales	$	111,879	$	67,224	$	44,655		66.4	%
Consolidated derivatives realized		6,212		806		5,406		670.7	%
Total oil and gas revenue and derivatives realized	$	118,091	$	68,030	$	50,061		73.6	%
Total Mcfe production		14,219,868		7,391,396		6,828,472		92.4	%
Average realized price per Mcfe, including the effects of derivatives	$	8.30	$	9.20	$	(0.90	)	(9.8	%)

Average realized price received for oil and gas during 2011 was $8.30 per Mcfe, a decrease of 9.8%, or $0.90 per Mcfe, from the prior year. The average realized price for oil, including the effects of derivatives, in 2011 increased 28.5% or $20.05 per barrel, whereas the average realized price for natural gas, including the effects of derivatives, decreased 15.4%, or $0.92 per Mcf, from 2010. Our derivative activities effectively increased net realized prices by $0.44 per Mcfe in 2011 and $0.11 per Mcfe in 2010.

Production volume for 2011 increased 92.4% from 2010 primarily due to the success of our Marcellus Shale horizontal drilling plan in the Appalachian Basin, where production increased approximately 210.2%, or 6.8 Bcfe. Our production for 2011 averaged approximately 38,959 Mcfe per day of which 29.3% was attributable to the Illinois Basin and 70.7% to the Appalachian Basin.

Statements of Operations for the years ended December 31, 2011 and 2010 are as follows:

	December 31,
	2011		2010		Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	111,879	$	67,224	$	44,655			66.4	%
Field Services Revenue		2,518		1,366		1,152			84.3	%
Other Revenue		209		173		(164	)		(94.8	%)

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TOTAL OPERATING REVENUE	114,606		68,763		45,843		66.7	%
OPERATING EXPENSES
Production and Lease Operating Expense	33,116		24,656		8,460		34.3	%
General and Administrative Expense	23,636		17,141		6,495		37.9	%
(Gain) Loss on Disposal of Assets	502		(16,395	)	16,897		103.1	%
Impairment Expense	14,631		8,863		5,768		65.1	%
Exploration Expense	2,507		2,578		(71	)	(2.8	%)
Depreciation, Depletion, Amortization and Accretion	28,361		21,806		6,555		30.1	%
Field Services Operating Expenses	1,750		1,188		562		47.3	%
Other Operating Expense	819		153		666		N/M
TOTAL OPERATING EXPENSES	105,322		59,990		45,332		75.6	%
INCOME (LOSS) FROM OPERATIONS	9,284		8,773		511		5.8	%
OTHER INCOME (EXPENSE)
Interest Income	10		68		(58	)	(85.3	%)
Interest Expense	(2,019	)	(1,070	)	(949	)	88.7	%
Gain (Loss) on Derivatives, Net	18,916		6,055		12,861		212.4	%
Other Income (Expense)	79		(321	)	400		124.6	%
Gain (Loss) on Equity Method Investments	81		(200	)	281		140.5	%
TOTAL OTHER INCOME (EXPENSE)	17,067		4,532		12,535		276.6	%
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX	26,351		13,305		13,046		98.1	%
Income Tax Benefit (Expense)	(8,270	)	(5,500	)	(2,770	)	50.4	%
INCOME (LOSS) FROM CONTINUING OPERATIONS	18,081		7,805		10,276		131.7	%
Income (Loss) From Discontinued Operations, Net of Income Taxes	(33,457	)	(2,022	)	(31,435	)	N/M

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NET INCOME (LOSS)		(15,376	)		5,783			(21,159	)	N/M
Net Loss Attributable to Noncontrolling Interests		(7	)		(253	)		246		(97.2	%
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(15,369	)	$	6,036		$	(21,405	)	N/M

Field Services Revenue for 2011 of approximately $2.5 million increased $1.2 million, or 84.3%, from 2010. During 2010, we entered into a joint venture that specializes in the sourcing and transportation of water in the Marcellus Shale regions of the Appalachian Basin. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays has led to the growth of our field service activities, and particularly water transfer to service well completion activities.

Production and Lease Operating Expense increased approximately $8.5 million, or 34.3%, in 2011 from 2010. The increase is primarily due to processing and gathering fees incurred in our Butler County, Pennsylvania operating region. We produce wet gas in this region, which requires processing before it can be sold. As such, we jointly constructed a cryogenic gas processing plant for which we pay fees to have our gas transported and processed before sale. We incurred approximately $4.6 million in expenses related to processing and gathering during 2011 and approximately $0.3 million in 2010. Also contributing to our increased expenses was the growth of our Appalachian Basin operations, where we placed into service 51.0 gross (25.9 net) wells in 2011.

General and Administrative Expense of approximately $23.6 million for 2011 increased approximately $6.5 million, or 37.9%, from 2010. The increase in general and administrative costs is attributable to legal expenses, severance wages and an overall increase in headcount. We incurred $2.5 million in legal costs associated with the settlement of our leasing lawsuit in Westmoreland County, Pennsylvania. During 2011, we entered into separation agreements with several employees for which we incurred approximately $1.0 million in severance costs. The remainder of the increase during 2011 is primarily attributable to our continued efforts to hire and retain high quality personnel. We have incurred higher recruiting, wages and benefits costs to achieve this goal, which includes approximately $1.6 million in non-cash compensation in 2011 as compared to $0.9 million in 2010.

(Gain) Loss on Disposal of Assets for 2011 was a loss of approximately $0.5 million as compared to a gain of $16.4 million for 2010. From time to time, we sell or otherwise dispose of certain fixed assets and wells that are no longer effectively used by us, and a gain or loss may be recognized when such an asset is sold.

Impairment Expense increased to $14.6 million in 2011 from $8.9 million, or 65.1%, in 2010 and primarily relates to our exploration and production segment. We evaluate impairment of our properties when events occur that indicate that the carrying value of these properties may not be recoverable. During 2011 we incurred approximately $11.6 million of impairment expense related to conventional shallow natural gas properties in the Appalachian Basin due to their estimated fair value being less than their carrying value as of December 31, 2011. These wells are characterized as older wells that produce at much lower rates than the unconventional shale plays. While they are less capital intensive and have

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lower operating costs, their lower production levels combined with lower commodity pricing make them susceptible to impairment write downs. The remainder of our impairment in 2011 was primarily due to the expiration of leased acreage. During 2010, impairment expense was primarily related to two test wells in Clearfield County, Pennsylvania. We determined that the carrying value of these two test wells, which were in various stages of drilling and completion, was not recoverable due to a lack of a sales outlet and no then-current plans by us to complete the wells for commercial production. We periodically evaluate the capitalized costs associated with properties that are outside of our current scope of operations as to their recoverability based on changes brought about by economic factors and potential shifts in our business strategy. As economic and strategic conditions change and we continue to develop unproved properties, our estimates of impairment will likely change and we may increase or decrease expense.

Exploration Expense of oil and gas properties for 2011 decreased approximately $0.1 million from $2.6 million in 2010. Exploration costs incurred by us during 2011 and 2010 were primarily due to delay rental payments on undeveloped acreage and seismic and micro-seismic activities on our properties.

Depletion, Depreciation, Amortization and Accretion Expense of approximately $28.4 million for 2011 increased approximately $6.6 million, or 30.1%, from 2010. Depletion expenses incurred during 2010 were lower than what would normally be expected primarily due to the carry obligations by our joint venture partners, whereby our partners would fund the majority of the cost to drill and complete wells to earn their share of the working interest. We expect future depletion to trend more in line with production as the carry obligations have been expended, pending any future carry obligations.

Field Services Operating Expense for 2011 totaled approximately $1.8 million as compared to $1.2 million in 2010. These costs are comprised of operating expenses incurred in connection with our field services joint venture. Our field services operating expenses are largely variable in nature and fluctuate commensurate with our level of activity. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays has led to the growth of our field service activities, particularly those associated with water transfer for well completion operations. We did have any field service operations prior to 2010.

Interest Expense, net of Interest Income, for 2011 was approximately $2.0 million as compared to $1.0 million for 2010. The increase in interest expense, net of interest income, was primarily due to a higher average outstanding balance on our Senior Credit Facility.

Gain (Loss) on Derivatives, net for 2011 was a gain of approximately $18.9 million as compared to $6.1 million for 2010. This change was attributable to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the time we entered into a derivative contract, while gains would suggest the opposite. Our derivative program is designed to provide us with greater predictability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

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Net Income (Loss) Attributable to Rex Energy for 2011 was a loss of approximately $15.4 million, as compared to net income of approximately $6.0 million for 2010 as a result of the factors discussed above.

Comparison of the Year Ended December 31, 2010 to the Year Ended December 31, 2009

Oil and gas revenue for the years ended December 31, 2010 and 2009 is summarized in the following table:

	December 31,
	2010			2009		Change			%
Oil and Gas Revenue ($ in thousands):
Oil sales revenue	$	52,577		$	41,881		10,696			25.5	%
Oil derivatives realized (a)		(3,861	)		2,626		(6,487	)		(247.0	%)
Total oil revenue and derivatives realized	$	48,716		$	44,507		4,209			9.5	%
Gas sales revenue	$	13,789		$	6,460		7,329			113.5	%
Gas derivatives realized		4,667			3,216		1,451			45.1	%
Total gas revenue and derivatives realized	$	18,456		$	9,676		8,780			90.7	%
Total NGL revenue	$	858		$	193		665			344.6	%
Consolidated sales	$	67,224		$	48,534		18,690			38.5	%
Consolidated derivatives realized		806			5,842		(5,036	)		(86.2	%)
Total oil and gas revenue and derivatives realized	$	68,030		$	54,376		13,654			25.1	%
Total Mcfe production		7,391,396			5,877,060		1,514,336			25.8	%
Average realized price per Mcfe, including the effects of derivatives	$	9.20		$	9.25		(0.05	)		(0.5	%)

(a) 2009 oil derivatives realized excludes approximately $4.6 million in proceeds that were received upon the early settlement of oil hedges relating to the 2011 calendar year.

Average realized price received for oil and gas during 2010 was $9.20 per Mcfe, a decrease of 0.5%, or $0.05 per Mcfe, from the prior year. The average realized price for oil, including the effects of derivatives, in 2010 increased 14.0% or $8.63 per barrel, whereas the average realized price for natural

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gas, including the effects of derivatives, decreased 6.8%, or $0.43 per Mcf, from 2009. Our derivative activities effectively increased net realized prices by $0.11 per Mcfe in 2010 and $0.99 per Mcfe in 2009.

Production volume for 2010 increased 25.8% from 2009 primarily due to the success of our Marcellus Shale horizontal drilling plan in the Appalachian Basin, where production increased approximately 108%, or 1.7 Bcfe. Our production for 2010 averaged approximately 20,250 Mcfe per day of which 56.1% was attributable to the Illinois Basin and 43.9% to the Appalachian Basin.

Statements of Operations for the years ended December 31, 2010 and 2009 are as follows:

	December 31,
	2010			2009			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	67,224		$	48,534		$	18,690			38.5	%
Field Services Revenue		1,366			—			1,366			100.0	%
Other Revenue		173			157			16			10.2	%
TOTAL OPERATING REVENUE		68,763			48,691			20,072			41.2	%
OPERATING EXPENSES
Production and Lease Operating Expense		24,656			22,157			2,499			11.3	%
General and Administrative Expense		17,141			15,858			1,283			8.1	%
(Gain) Loss on Disposal of Assets		(16,395	)		427			(16,822	)		N/M
Impairment Expense		8,863			1,625			7,238			N/M
Exploration Expense		2,578			2,080			498			23.9	%
Depreciation, Depletion, Amortization and Accretion		21,806			25,205			(3,399	)		(13.5	%)
Field Services Operating Expense		1,188			—			1,188			100.0	%
Other Operating Expense		153			—			153			100.0	%
TOTAL OPERATING EXPENSES		59,990			67,352			(7,362	)		(10.9	%)
INCOME (LOSS) FROM OPERATIONS		8,773			(18,661	)		27,434			147.0	%

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OTHER INCOME (EXPENSE)
Interest Income		68			7			61		N/M
Interest Expense		(1,070	)		(833	)		(237	)	28.5	%
Gain (Loss) on Derivatives, Net		6,055			(7,913	)		13,968		(176.5	%)
Other Income (Expense)		(321	)		(161	)		(160	)	99.4	%
Gain (Loss) on Equity Method Investments		(200	)		(9	)		(191	)	N/M
TOTAL OTHER INCOME (EXPENSE)		4,532			(8,909	)		13,441		150.9	%
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		13,305			(27,570	)		40,875		(148.3	%)
Income Tax Benefit (Expense)		(5,500	)		11,002			(16,502	)	(150.0	%)
INCOME (LOSS) FROM CONTINUING OPERATIONS		7,805			(16,568	)		24,373		(147.1	%)
Income (Loss) From Discontinued Operations, Net of Income Taxes		(2,022	)		323			(2,345	)	N/M
NET INCOME (LOSS)		5,783			(16,245	)		22,028		(135.6	%)
Net Loss Attributable to Noncontrolling Interests		(253	)		(12	)		(241	)	N/M
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	6,036		$	(16,233	)	$	22,269		(137.2	%)

Field Services Revenue for 2010 of approximately $1.4 million was attributable to the operations of Water Solutions, or 80% owned joint venture that specializes in the sourcing and transportation of water in the Marcellus Shale regions of the Appalachian Basin. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays has led to the growth of our field service activities, and particularly water transfer to service well completion activities.

Production and Lease Operating Expense increased approximately $2.5 million, or 11.3%, in 2010 from 2009. The increase in expense was primarily due to seasonal repair and maintenance work being performed in our Illinois Basin operations. These repair and maintenance activities were delayed during 2009 due, in part, to periods of depressed oil prices during the year. Also contributing to our higher production expenses during the year was the continued expansion of our Marcellus Shale operations, where we began to incur costs to transport and process our natural gas in our Butler County, Pennsylvania project area. Lease operating expense per Mcfe decreased approximately 11.4% from 2009 to $3.34 per Mcfe in 2010, which was the result of our increased production.

General and Administrative Expense of approximately $17.1 million for 2010 increased approximately $1.3 million, or 8.1%, from 2009. These expenses increased from 2009 to 2010 primarily

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due to expenses recognized with respect to Water Solutions, for which we fully consolidate the results of operations. This entity did not begin operations until December 2009. We also incurred additional G&A expenses in 2010 for legal costs incurred in connection with the Sumitomo transaction, recruiting and relocation expenses associated with the hiring of certain executives and senior management, and in connection with an increase in our overall headcount.

(Gain) Loss on Disposal of Assets for 2010 was a gain of approximately $16.4 million as compared to a loss $0.4 million for 2009. From time to time, we sell or otherwise dispose of certain fixed assets and wells that are no longer effectively used by us, and a gain or loss may be recognized when such an asset is sold. The gain in 2010 was primarily due to the Sumitomo joint venture transaction while the loss incurred during 2009 was a result of the disposal of our Southwest Region assets.

Impairment Expense increased to $8.9 million in 2010 from $1.6 million in 2009 and primarily relates to our exploration and production segment. We evaluate impairment of our properties when events occur that indicate that the carrying value of these properties may not be recoverable. During 2010, we determined that the carrying value of two of our test wells, which were in various stages of drilling and completion, in Clearfield County, Pennsylvania, were not recoverable due to a lack of a sales outlet and no then-current plans by us to complete the wells for commercial production. In addition, the capitalized costs associated with properties that are outside of our current scope of operations are periodically evaluated as to their recoverability based on changes brought about by economic factors and potential shifts in our business strategy. As economic and strategic conditions change and we continue to develop unproved properties, our estimates of impairment will likely change and we may increase or decrease expense.

Exploration Expense of oil and gas properties for 2010 increased to approximately $2.6 million from $2.1 million in 2009. Exploration costs incurred by us during 2010 and 2009 were primarily due to delay rental payments on undeveloped acreage and seismic and micro-seismic activities on our properties.

Depletion, Depreciation, Amortization and Accretion Expense of approximately $21.8 million for 2010 decreased approximately $3.4 million, or 13.5%, from 2009. This decrease can be primarily explained by the upward revision in the estimated lives of our estimated proved reserves. We calculate our depletion on a units-of-production basis, which decelerated in relation to our higher estimated proved reserves base.

Field Services Operating Expense for 2010 totaled approximately $1.2 million as compared to $0 in 2009. These costs are comprised of operating expenses incurred in connection with our field services joint venture. Our field services operating expenses are largely variable in nature and fluctuate commensurate with our level of activity. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays has led to the growth of our field service activities, particularly those associated with water transfer for well completion operations. We did have any field service operations prior to 2010.

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Interest Expense, net of Interest Income, for 2010 was approximately $1.0 million as compared to $0.8 million for 2009. The increase in interest expense, net of interest income, was primarily due to our higher average outstanding balance on our Senior Credit Facility.

Gain (Loss) on Derivatives, net for 2010 was a gain of approximately $6.1 million as compared to a loss of $7.9 million for 2009. The change was attributed to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the time we entered into a derivative contract, while gains would suggest the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

Other Expense increased by $0.2 million to approximately $0.3 million in 2010. The increase in Other Expense was primarily attributable to expenses incurred in connection with ensuring the pipeline integrity of a gathering system contributed to our Keystone Midstream Services, LLC joint venture, of which we are the 28% owner.

Net Income (Loss) Attributable to Rex Energy for 2010 was income of approximately $6.0 million, as compared to a net loss of approximately $16.2 million for 2009 as a result of the factors discussed above.

Capital Resources and Liquidity

Our primary financial resource is our base of oil and gas reserves. During 2011, $275.4 million of capital, which excludes our joint venture investments, was expended on drilling projects, facilities and related equipment and acquisitions of unproved acreage. The capital program was funded by net cash flow from operations and through borrowings on our Senior Credit Facility and our second lien credit agreement. Our 2012 capital budget of $155.3 million is expected to continue to be funded primarily by cash flow from operations, non-core asset sales and borrowings under our credit agreements. We currently believe that we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a significant drop in commodity prices, particularly natural gas, or a reduction in production or reserves could adversely affect our ability to fund capital expenditures and meet our financial obligations. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may also elect to issue additional shares of stock, subordinated notes or other securities to fund capital expenditures, acquisitions, extend maturities or to repay debt. On February 6, 2012, we completed an underwritten public offering of 8,050,000 shares of our common stock, which included 1,050,000 shares of common stock issued upon the full exercise of the underwriters’ over-allotment option, at a public offering price of $9.25 per share. The net proceeds of the transaction are expected to be approximately $70.6 million, after deducting underwriting discounts, commissions and estimated offering expense. We have used the proceeds of the offering to repay borrowings under our Senior Credit Facility.

Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce

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our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of product prices on cash flow can be mitigated through the use of commodity derivatives. If we are unable to replace our oil and gas reserves through our acquisitions, development or exploration programs, we may also suffer a reduction in our operating cash flow and access to funds under the senior credit facility. Under extreme circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

Our cash flow from operations is driven by commodity prices and production volumes. Prices for oil and gas are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from heightened demand for hydrocarbons from emerging nations. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Cash flows from operations and borrowings from our senior credit facility have been primarily used to fund exploration and development of our oil and gas interests. As of December 31, 2011, we had $80.0 million available for borrowing under our senior credit facility of $255.0 million and $50.0 million available for borrowing under our second lien credit agreement of $100.0 million. As of December 31, 2011, we were in compliance with all required debt covenants.

In addition, we have utilized two joint venture agreements with Sumitomo and Williams to supplement our capital outlay to assist in sustaining our growth prospects. Through the Sumitomo PEA, we received approximately $99.5 million in cash in addition to approximately $58.8 million in drilling expenses in our joint venture project areas. As of December 31, 2011, Sumitomo fulfilled its drilling carry obligation in full. In addition to the drilling carry, Sumitomo has also agreed to pay to us a management fee of $150 per acre for leases acquired in our Butler County, Pennsylvania project area.

Financial Condition and Cash Flows for the Years Ended December 31, 2011, 2010 and 2009

The following table summarizes our sources and uses of funds for the periods noted:

	For the Years Ended December 31, ($ in Thousands)
	2011			2010			2009
Cash flows provided by operating activities	$	64,507		$	34,102		$	20,774
Cash flows used in investing activities		(276,574	)		(94,921	)		(30,061	)

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Cash flows provided by financing activities		212,855		66,245		7,823
Net increase (decrease) in cash and cash equivalents	$	788	$	5,426	$	(1,464	)

Net cash provided by operating activities increased by approximately $30.4 million in 2011 when compared to 2010, to $64.5 million. This increase is primarily due to increased oil and natural gas production, in addition to higher crude oil prices as compared to 2010. Partially offsetting these increases were higher production and G&A costs. Net cash provided by operating activities increased by approximately $13.3 million in 2010 when compared to 2009, to $34.1 million. In 2010, cash flows increased primarily due to higher revenues attributable to increased production and more favorable commodity prices. These increases were partially offset by higher lease operating expense, G&A expense, field services operating expense and other operating expense which were related to our increased activity levels.

Net cash used in investing activities increased by approximately $181.7 million in 2011 when compared to 2010, to $276.6 million. Approximately $118.8 million of this increase is due to our growth and expansion during the year as we drilled, completed and placed into service wells in our Appalachian Basin region. Also contributing to the increase in net investing were lower proceeds on sale of assets of $76.5 million during 2011, which was primarily due to the Sumitomo joint venture that occurred in 2010. Net cash used in investing activities increased by approximately $64.9 million in 2010 when compared to 2009, to $94.9 million. During 2009, we decreased our normal development activities and increased our focus on more strategic projects, such as Marcellus Shale exploration. During 2010, our investment activity increased as we expanded our exploration of the Marcellus Shale in the Appalachian Basin and the Niobrara formation in the DJ Basin. Partially offsetting our expenditures in 2010 were proceeds received upon the closing of our joint venture with Sumitomo, where we received cash in exchange for a partial interest in wells, acreage and other equipment.

Net cash provided by financing activities increased by approximately $146.6 million in 2011 when compared to 2010, to $212.9 million. During 2011, we increased our borrowings under our credit agreements by $155.0 million and reduced repayments of debt by $73.0 million. Net cash provided by financing activities increased by approximately $58.4 million in 2010 when compared to 2009, to $66.2 million. During 2010, we received net proceeds from the issuance of common stock of approximately $80.2 million. This increase in cash flow was partially offset by net repayments of long-term debt of approximately $13.0 million in 2010 as compared to net proceeds in 2009 of approximately $8.0 million.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases or decreases, there could be a corresponding increase or decrease in our operating costs, as well as an increase or decrease in revenues. Inflation has had a minimal effect on us.

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Critical Accounting Policies and Recent Accounting Pronouncements

The preparation of financial statements in conformity with United States generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future cash flows, asset retirement obligations, impairment (when applicable) of undeveloped properties, the collectability of outstanding accounts receivable, fair values of financial derivative instruments, contingencies and the results of current and future litigation. Oil and natural gas estimates, which are the basis for units-of-production depletion, have numerous inherent uncertainties. The certainty of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. These prices have been volatile in the past and are expected to be volatile in the future.

The significant estimates are based on current assumptions that may be materially affected by changes in future economic conditions such as the market prices received for sales of oil and natural gas, interest rates, and our ability to generate future income. Future changes in these assumptions may materially affect these significant estimates in the near term.

Natural Gas and Oil Reserve Quantities

Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2011 and 2010, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. The technical persons responsible for preparing the estimates of our proved reserves meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as intense management review and approval.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil and natural gas reserves, and the projected cash flows

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derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC, including the rule revisions designed to modernize the oil and gas company reserves reporting requirements and which we adopted effective December 31, 2009. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The certainty of our reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. Any of the assumptions inherent in these factors could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas and oil eventually recovered. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new DD&A rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.

Derivative Instruments

We use put and call options (collars), fixed rate swap contracts, swaptions, puts and put spreads to manage price risks in connection with the sale of oil and natural gas. We have also, in the past, used interest rate swap agreements to manage interest rate risks associated with our variable rate credit facility. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third party providers. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. We do not designate our derivatives as hedging instruments, therefore, any changes in fair value are recognized immediately in earnings.

Oil and Natural Gas Property, Depreciation and Depletion

We account for natural gas and oil exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by- property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of natural gas and oil, are capitalized.

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Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 30 years.

When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and oil prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. When evaluating our unproved oil and gas properties, we utilize active market prices for similar acreage to use as a comparison tool against the carrying value of our properties. If the active market prices for similar acreage do not support our carrying values we then utilize estimates of future value that will be created from the future development of these properties. If future estimated fair value of these properties is lower than the capitalized cost, the capitalized cost is reduced to the estimated future fair value. We recognized approximately $14.6 million, $8.9 million and $1.6 million of impairment from continuing operations on certain oil and gas properties for the years ending December 31, 2011, 2010 and 2009, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 18,Impairment Expense, to our Consolidated Financial Statements.

Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.

Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated DD&A are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

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Deferred Financing Costs and Other Assets – Net

At December 31, 2011, our intangible assets from continuing operations consisted of $3.3 million, which is primarily made up of loan costs that are amortized using the straight line method over their respective estimated lives, which is, on average, three to five years. We amortize any costs incurred to renew or extend the terms of existing intangible assets over the contract term or estimated useful life, as applicable, using the straight-line method. For the years ended December 31, 2011, 2010, and 2009, we recorded amortization expense from continuing operations of $0.8 million, $0.5 million and $0.4 million, respectively.

Future Abandonment Cost

Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.

Deferred Income Taxes

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized.

We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

Contingent Liabilities

A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of

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our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. We have recognized an accrued liability of approximately $0.1 million at December 31, 2011 for the estimated cost of pending litigation matters.

Stock-based Compensation

We recognize in the Consolidated Financial Statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights.

The benefits associated with the tax deductions in excess of recognized compensation cost are reported as a financing cash flow. This requirement reduces net operating cash flows and increases net financing cash flows. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2011-11,Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. ASU 2011-11 provides new disclosure requirements related to offsetting arrangements to allow investors to better compare financial statements prepared in accordance with IFRS and U.S. GAAP. The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods, including retrospective application for all comparative periods presented. Although we currently are not engaged in any arrangements that would be effected by these disclosure requirements, we believe that ASU 2011-11 may have a material impact on future disclosures pending our entrance into an offsetting arrangement.

In May 2011, the FASB issued ASU 2011-04,Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-04 generally provides a uniform framework for fair value measurements and related disclosures between GAAP and International Financial Reporting Standards (“IFRS”). Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements, quantitative information about unobservable inputs used, a description of the valuation process used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a nonfinancial asset that is different from the asset’s highest and best use, the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required, the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosures of all transfers between Level 1 and Level 2 of the fair value hierarchy. This update is

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effective for annual and interim periods beginning on or after December 31, 2011. We adopted ASU 2011-04 on January 1, 2012, with no material impact.

In December 2010, the FASB issued ASU 2010-29,Disclosure of Supplementary Pro Forma Information for Business Combinations (“ASU 2010-29”). The amendments to the codification clarify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Additionally, the supplemental pro forma disclosures under Topic 805 have been expanded to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments in ASU 2010-29 are effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Although we have not entered into any significant business combinations in our recent history, we believe that ASU 2010-29 may have a material impact on future disclosures depending on the size and nature of any future business combinations that we may enter into. We adopted ASU 2010-29 on January 1, 2011, with no material impact.

Volatility of Oil and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.

We account for our natural gas and oil exploration and production activities under the successful efforts method of accounting (for additional information, see Note 2, Summary of Significant Accounting Policies, of our Consolidated Financial Statements).

To mitigate some of our commodity price risk we engage periodically in certain other limited derivative activities, including price swaps and costless collars, to establish some price floor protection.

For the twelve-month period ended December 31, 2011, the net realized gain on oil and natural gas derivatives was approximately $6.2 million. For the twelve-month period ended December 31, 2010, the net realized gain on oil and natural gas derivatives was approximately $0.1 million.

For the twelve month period ended December 31, 2011, the net unrealized gain on oil and natural gas derivatives was approximately $12.7 million, as compared to a net unrealized gain of approximately $6.0 million on oil and natural gas derivatives for 2010. The net unrealized gains and losses are reported as Gain (Loss) on Derivatives, net in the Consolidated Statements of Operations.

While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of oil and natural gas. We enter into the majority of our derivative transactions with four counterparties and have a netting agreement in place with those counterparties. We do not obtain collateral to support the agreements, but we believe our credit

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risk is currently minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivative arrangements generally do not apply to all of our production, and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time.

For a summary of our current oil and natural gas derivative positions at December 31, 2011, refer to Note 12, Fair Value of Financial Instruments and Derivative Instruments, of our Consolidated Financial Statements.

Contractual Obligations

In addition to our capital expenditure program, we are committed to making cash payments in the future on various types of contracts and obligations. As of December 31, 2011, we do not have any off-balance sheet debt or other such unrecorded obligations and we have not guaranteed the debt of any other party. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2011. In addition to the contractual obligations listed in the table below, our balance sheet at December 31, 2011 reflects accrued interest on our bank debt of $0.4 million which was paid in January 2012.

The following summarizes our contractual financial obligations for continuing operations at December 31, 2011 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities.

	Payment due by period (in thousands)
	2012		2013		2014		2015		2016		Thereafter		Total
Bank Debt (a)	$	—	$	—	$	—	$	175,000	$	50,000	$	—	$	225,000
Operating Leases		497		548		104		44		—		—		1,193
Other Loans and Notes Payable		406		138		—		—		—		—		544
Leasing Commitments		1,172		—		—		—		—		—		1,172
Derivative Obligations (b)		—		—		642		—		—		—		642
Firm Commitments (c)		1,164		6,200		6,342		7,051		7,051		42,613		70,421
Asset Retirement Obligations (d)		600		563		684		531		475		15,817		18,670
Total Contractual Obligations	$	3,839	$	7,449	$	7,772	$	182,626	$	57,526	$	58,430	$	317,642

(a) Due at termination date of respective facility. Interest paid on our bank credit facilities would be approximately $8.5 million per year from 2012 through 2015 and $4.2 million in 2016 assuming no change in the interest rate or outstanding balance.

(b) Derivative obligations represent net open derivative contracts valued as of December 31, 2011.

(c) Includes sales, gathering and processing agreements.

(d) The ultimate settlement and timing cannot be precisely determined in advance.

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Interest Rates

At December 31, 2011, we had $225.0 million of debt outstanding under our senior credit facility and second lien credit agreement. This bears interest at floating rates, which averaged 2.5% and 8.3% on our senior credit facility and second lien credit agreement, respectively, at December 31, 2011. The 30-day London Interbank Offered Rate (“LIBOR”) on December 31, 2011 was 0.3%.

Off-Balance Sheet Arrangements

We do not currently use any off-balance sheet arrangements to enhance our liquidity or capital resource position, or for any other purpose.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REX ENERGY CORPORATION

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm – 2011		F-2
Report of Independent Registered Public Accounting Firm – 2010 and 2009		F-3
Consolidated Balance Sheets at December 31, 2011 and 2010		F-5
Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009		F-7
Consolidated Statements of Changes in Noncontrolling Interests and Stockholders’ Equity (Deficit) for the Years Ended December 31, 2011, 2010 and 2009		F-9
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		F-10
Notes to the Consolidated Financial Statements		F-12

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors

Rex Energy Corporation:

We have audited the accompanying consolidated balance sheet of Rex Energy Corporation and subsidiaries (the Company) as of December 31, 2011 and the related consolidated statements of operations, changes in noncontrolling interests and stockholders’ equity (deficit), and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. The accompanying consolidated financial statements of the Company as of December 31, 2010, were audited by other auditors whose reports thereon dated March 3, 2011, expressed an unqualified opinion on those statements, before the effects of the adjustments to retrospectively adjust for disclosures for a change in the composition of reportable segments discussed in Note 3 to the consolidated financial statements.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2011, and the results of their operations and their cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.

We also have audited adjustments to the 2010 consolidated financial statements to retrospectively adjust the disclosures for a change in the composition of reportable segments discussed in Note 3 to the consolidated financial statements. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2010 consolidated financial statements of the Company other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2010 consolidated financial statements taken as a whole.

We have also audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the Company’s internal controls over financial reporting as of December 31, 2011, based on criteria established in Internal Controls—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 15, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

Dallas, Texas

March 15, 2012 except for Notes 3 and 26,

as to which the dates are

November 13, 2012

F-2

Report of Independent Registered Public Accounting Firm

To the Board of Directors and

Stockholders of

Rex Energy Corporation

State College, Pennsylvania

We have audited, before the effects of the retrospective adjustments to the disclosures for a change in the composition of reportable segments discussed in Note 3 to the consolidated financial statements, the accompanying consolidated balance sheet of Rex Energy Corporation as of December 31, 2010, and the related consolidated statements of operations, owners’ equity and noncontrolling interests, and cash flows for each of the years in the two-year period ended December 31, 2010. We have also audited Rex Energy Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Rex Energy Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

F-3

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

In our opinion, the financial statements referred to above, before the effects of the retrospective adjustments to the disclosures for a change in the composition of reportable segments discussed in Note 3 to the consolidated financial statements, present fairly, in all material respects, the consolidated financial position of Rex Energy Corporation as of December 31, 2010, and the consolidated results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, Rex Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We were not engaged to audit, review, or apply any procedures to the retrospective adjustments to the disclosures for a change in the composition of reportable segments discussed in Note 3 to the consolidated financial statements and, accordingly, we do not express an opinion or any other form of assurance about whether such retrospective adjustments are appropriate and have been properly applied. Those retrospective adjustments were audited by other auditors.

Malin, Bergquist & Company, LLP

Pittsburgh, Pennsylvania

March 3, 2011

F-4

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in Thousands, Except Share and Per Share Data)

	December 31, 2011			December 31, 2010
ASSETS
Current Assets
Cash and Cash Equivalents	$	11,796		$	11,008
Accounts Receivable		17,717			28,849
Short-Term Derivative Instruments		10,404			4,564
Assets Held For Sale		24,808			47,884
Inventory, Prepaid Expenses and Other		1,191			1,327
Total Current Assets		65,916			93,632
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		349,938			241,586
Unevaluated Oil and Gas Properties		123,241			64,115
Other Property and Equipment		43,542			42,178
Wells and Facilities in Progress		66,548			17,026
Pipelines		4,408			4,080
Total Property and Equipment		587,677			368,985
Less: Accumulated Depreciation, Depletion and Amortization		(107,433	)		(93,062	)
Net Property and Equipment		480,244			275,923
Restricted Cash		25			16,111
Deferred Financing Costs and Other Assets – Net		3,380			1,570
Equity Method Investments		41,683			18,399
Long-Term Deferred Tax Asset		1,727			0
Long-Term Derivative Instruments		8,576			1,450
Total Assets	$	601,551		$	407,085
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	41,558		$	46,192

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Accrued Expenses		15,682			8,691
Short-Term Derivative Instruments		2,363			1,860
Current Deferred Tax Liability		2,141			1,908
Liabilities Related to Assets Held for Sale		1,622			4,686
Total Current Liabilities		63,366			63,337
Senior Secured Line of Credit and Long-Term Debt		225,138			10,120
Long-Term Derivative Instruments		1,275			1,517
Long-Term Deferred Tax Liability		84			5,930
Other Deposits and Liabilities		744			4,283
Future Abandonment Cost		18,670			17,222
Total Liabilities		309,277			102,409
Commitments and Contingencies (See Note 9)
Owners’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 44,859,220 shares issued and outstanding on December 31, 2011 and 44,306,677 shares issued and outstanding on December 31, 2010		44			44
Additional Paid-In Capital		376,843			373,856
Accumulated Deficit		(84,888	)		(69,519	)
Rex Energy Owners’ Equity		291,999			304,381
Noncontrolling Interests		275			295
Total Owners’ Equity		292,274			304,676
Total Liabilities and Owners’ Equity	$	601,551		$	407,085

See accompanying notes to the consolidated financial statements

F-6

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

($ and Shares in Thousands, Except Share and Per Share Data)

		Year Ended December 31,
		2011			2010			2009
OPERATING REVENUE
Oil, Natural Gas and NGL Sales		$	111,879		$	67,224		$	48,534
Field Services Revenue			2,518			1,366			0
Other Revenue			209			173			157
TOTAL OPERATING REVENUE			114,606			68,763			48,691
OPERATING EXPENSES
Production and Lease Operating Expense			33,116			24,656			22,157
General and Administrative Expense			23,636			17,141			15,858
(Gain) Loss on Disposal of Asset			502			(16,395	)		427
Impairment Expense			14,631			8,863			1,625
Exploration Expense			2,507			2,578			2,080
Depreciation, Depletion, Amortization and Accretion	��		28,361			21,806			25,205
Field Services Operating Expense			1,750			1,188			0
Other Operating Expense			819			153			0
TOTAL OPERATING EXPENSES			105,322			59,990			67,352
INCOME (LOSS) FROM OPERATIONS			9,284			8,773			(18,661	)
OTHER INCOME (EXPENSE)
Interest Income			10			68			7
Interest Expense			(2,019	)		(1,070	)		(833	)
Gain (Loss) on Derivatives, Net			18,916			6,055			(7,913	)
Other Income (Expense)			79			(321	)		(161	)
Income (Loss) from Equity Method Investments			81			(200	)		(9	)
TOTAL OTHER INCOME (EXPENSE)			17,067			4,532			(8,909	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX			26,351			13,305			(27,570	)

F-7

Income Tax Benefit (Expense)		(8,270	)		(5,500	)		11,002
INCOME (LOSS) FROM CONTINUING OPERATIONS		18,081			7,805			(16,568	)
Income (Loss) From Discontinued Operations, Net of Income Taxes		(33,457	)		(2,022	)		323
NET INCOME (LOSS)		(15,376	)		5,783			(16,245	)
Net Loss Attributable to Noncontrolling Interests		(7	)		(253	)		(12	)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(15,369	)	$	6,036		$	(16,233	)
Earnings Per Common Share:
Basic – income (loss) from continuing operations attributable to Rex common shareholders	$	0.41		$	0.18		$	(0.45	)
Basic – income (loss) from discontinued operations attributable to Rex common shareholders		(0.76	)		(0.05	)		0.01
Basic – net income (loss) attributable to Rex common shareholders	$	(0.35	)	$	0.13		$	(0.44	)
Basic – weighted average shares of common stock outstanding		43,930			43,281			36,806
Diluted – income (loss) from continuing operations attributable to Rex common shareholders	$	0.41		$	0.18		$	(0.45	)
Diluted – income (loss) from discontinued operations attributable to Rex common shareholders		(0.76	)		(0.05	)		0.01
Diluted – net income (loss) attributable to Rex common shareholders	$	(0.35	)	$	0.13		$	(0.44	)
Diluted – weighted average shares of common stock outstanding		44,476			43,670			36,806

See accompanying notes to the consolidated financial statements

F-8

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN NONCONTROLLING INTERESTS

AND STOCKHOLDERS’ EQUITY (DEFICIT)

(in Thousands)

	Common Stock				Additional Paid-In Capital		Accumulated Deficit			Rex Energy Owners’ Equity			Noncontrolling Interests			Total Owners’ Equity
	Shares		Par
Balance December 31, 2008		36,590	$	37	$	291,133	$	(59,322	)	$	231,848		$	0		$	231,848
Non-cash compensation expense		0		0		1,239		0			1,239			0			1,239
Capital contributions		0		0		0		0			0			3,355			3,355
Restricted stock, net		228		0		0		0			0			0			0
Net Loss		0		0		0		(16,233	)		(16,233	)		(12	)		(16,245	)
Balance December 31, 2009		36,818		37		292,372		(75,555	)		216,854			3,343			220,197
Non-cash compensation expense		0		0		965		0			965			0			965
Issuance of 6,900,000 shares of common stock net of issuance costs of $0.3 million		6,900		7		80,192		0			80,199			0			80,199
Capital contributions		0		0		0		0			0			287			287
Restricted stock, net		567		0		0		0			0			0			0
Stock option exercises		22		0		327		0			327			0			327
Deconsolidation of Keystone Midstream Services, LLC		0		0		0		0			0			(3,082	)		(3,082	)
Net Income (Loss)		0		0		0		6,036			6,036			(253	)		5,783
Balance December 31, 2010		44,307		44		373,856		(69,519	)		304,381			295			304,676
Non-cash compensation expense		0		0		1,625		0			1,625			0			1,625
Capital contributions (distributions), net		0		0		0		0			0			(13	)		(13	)
Restricted stock, net		413		0		0		0			0			0			0
Stock option exercises		139		0		1,362		0			1,362			0			1,362
Net Loss		0		0		0		(15,369	)		(15,369	)		(7	)		(15,376	)
Balance December 31, 2011		44,859	$	44	$	376,843	$	(84,888	)	$	291,999		$	275		$	292,274

See accompanying notes to the consolidated financial statements

F-9

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in Thousands)

	For the Years Ended December 31,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(15,376	)	$	5,783		$	(16,245	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
(Gain) Loss from Equity Method Investments		(81	)		200			9
Non-cash Expenses		1,745			1,251			1,897
Depreciation, Depletion, Amortization and Accretion		28,446			21,806			25,205
Deferred Income Tax Expense (Benefit)		(7,339	)		3,771			(10,713	)
Unrealized (Gain) Loss on Derivatives		(12,704	)		(5,960	)		17,002
Dry Hole Expense		32,769			3			135
(Gain) Loss on Sale of Assets		502			(16,395	)		427
Impairment Expense		27,808			8,863			1,625
Changes in operating assets and liabilities
Accounts Receivable		11,118			(14,527	)		(7,995	)
Inventory, Prepaid Expenses and Other Assets		86			(216	)		344
Accounts Payable and Accrued Expenses		(1,128	)		32,323			8,801
Other Assets and Liabilities		(1,339	)		(2,800	)		282
NET CASH PROVIDED BY OPERATING ACTIVITIES		64,507			34,102			20,774
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Phase I and Phase II Leasing Initiative		3,209			6,352			0
Proceeds from Joint Ventures		0			0			3,120
Change in Restricted Cash		16,086			(16,086	)		0
Equity Method Investments		(23,204	)		(14,018	)		(309	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		2,729			79,229			17,998
Acquisitions of Undeveloped Acreage		(78,569	)		(72,385	)		(17,898	)

F-10

Capital Expenditures for Development of Oil & Gas Properties and Equipment		(196,825	)		(78,013	)		(32,972	)
NET CASH USED IN INVESTING ACTIVITIES		(276,574	)		(94,921	)		(30,061	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		240,000			85,000			27,000
Repayments of Long-Term Debt and Lines of Credit		(25,000	)		(98,000	)		(19,000	)
Repayments of Loans and Other Notes Payable		(879	)		(753	)		(177	)
Debt Issuance Costs		(2,615	)		(701	)		0
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		0			80,192			0
Proceeds from the Exercise of Stock Options		1,362			220			0
Capital Distributions by the Partners of Equity Method Investments and Consolidated Joint Ventures		(20	)		0			0
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures		7			287			0
NET CASH PROVIDED BY FINANCING ACTIVITIES		212,855			66,245			7,823
NET INCREASE (DECREASE) IN CASH		788			5,426			(1,464	)
CASH – BEGINNING		11,008			5,582			7,046
CASH – ENDING	$	11,796		$	11,008		$	5,582
SUPPLEMENTAL DISCLOSURES
Interest Paid		1,549			846			581
Taxes Paid		312			299			0
NON-CASH ACTIVITIES
Equipment Financing		474			1,336			542
Equipment Contributed by Consolidated Joint Ventures		0			0			3,355

See accompanying notes to the consolidated financial statements

F-11

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent oil and gas company operating in the Appalachian Basin and the Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale drilling projects and Utica Shale and Upper Devonian Shale exploration activities. In the Illinois Basin, in addition to our developmental oil drilling, we are focused on the implementation of enhanced oil recovery on our properties. We pursue a balanced growth strategy of pursuing our higher potential exploration drilling prospects and actively seeking to acquire complementary oil and natural gas properties.

The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

Certain prior year amounts have been reclassified to conform to the report classifications for the year ended December 31, 2011, with no effect on previously reported net income, net income per share, accumulated deficit or stockholders’ equity. All prior year amounts that have been reclassified are immaterial.

We consolidate all of our subsidiaries in the accompanying Consolidated Balance Sheets as of December 31, 2011 and 2010 and the Consolidated Statements of Operations, Cash Flows and Changes in Noncontrolling Interests and Stockholders’ Equity (Deficit) of the years ended December 31, 2011, 2010 and 2009. Investments in unconsolidated affiliates in which we are able to exercise significant influence are accounted for using the equity method. All intercompany transactions and accounts have been eliminated.

Discontinued Operations

During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado. In March 2009, we completed the sale of certain oil and gas leases, wells and related assets predominantly located in the Permian Basin in the states of Texas and New Mexico. Pursuant to the rules for discontinued operations, these assets have been classified as Assets Held for Sale on our Consolidated Balance Sheets and the results of operations are reflected as Discontinued Operations in our Consolidated Statements of Operations. Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or

F-12

results from our discontinued operations. For additional information see Note 5, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

Subsidiary Guarantors

We filed a registration statement on Form S-3, which became effective June 15, 2011, with respect to certain securities described therein, including debt securities, which may be guaranteed by certain of our subsidiaries. Rex Energy Corporation is a holding company with no independent assets or operations. We contemplate that if guaranteed debt securities are offered pursuant to the registration statement, all guarantees will be full and unconditional and joint and several and any subsidiaries other than the subsidiary guarantors will be minor. In addition, there are no significant restrictions on the ability of Rex Energy Corporation to receive funds from our subsidiaries through dividends, loans, advances or otherwise.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates made in preparing these Consolidated Financial Statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation allowance and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates and our ability to generate future income.

Cash and Cash Equivalents

We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents. As of December 31, 2010, we had approximately $16.1 million accounted for as Restricted Cash on our Consolidated Balance Sheet. The amounts as of December 31, 2010, are primarily related to funds prepaid to us from Sumitomo for the purpose of acquiring mineral leases in Butler County, Pennsylvania, described as Phase I leases in Note 4, Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements.

Accounts Receivable

F-13

Our trade accounts receivable, which are primarily from oil and natural gas sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and recorded bad debts as necessary.

We use the allowance method to account for uncollectible accounts receivable. A reserve is recorded for amounts we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.

To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets.

At December 31, 2011, we carried approximately $13.6 million in production receivable, of which approximately $12.9 million were production receivables due from three purchasers. At December 31, 2010, we carried approximately $8.1 million in production receivable, of which approximately $7.3 million were production receivables due from three purchasers. In addition, we carried approximately $3.0 million in receivables from Sumitomo Corporation at December 31, 2011 and $19.2 million at December 31, 2010 (see Note 3, Business and Oil and Gas Property Acquisition Dispositions, to our Consolidated Financial Statements) that was in relation to our joint operations.

Inventory

Inventory is valued at the lower of cost or market value and consists of our ownership interest in oil and NGLs held in terminal tanks located in the field. Oil and NGL cost basis is calculated using the average cost method, with average cost defined as production and lease operating expenses net of DD&A. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory.

Oil and Natural Gas Property, Depreciation and Depletion

We account for natural gas and oil exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by- property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves,

F-14

including the costs of all development well and related equipment used in the production of natural gas and oil, are capitalized.

Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years.

When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and oil prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. When evaluating our unproved oil and gas properties, we utilize active market prices for similar acreage to use as a comparison tool against the carrying value of our properties. If the active market prices for similar acreage do not support our carrying values we then utilize estimates of future value that will be created from the future development of these properties. If future estimated fair value of these properties is lower than the capitalized cost, the capitalized cost is reduced to the estimated future fair value. We recognized approximately $14.6 million, $8.9 million and $1.6 million of impairment from continuing operations on certain oil and gas properties for the years ending December 31, 2011, 2010 and 2009, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 18, Impairment Expense, to our Consolidated Financial Statements.

Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.

Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated DD&A are removed from the property accounts and the

F-15

resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Natural Gas and Oil Reserve Quantities

Our estimate of estimated proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2011 and 2010, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as intense management review and approval.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil and natural gas reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC, including the rule revisions designed to modernize the oil and gas company reserves reporting requirements and which we adopted effective December 31, 2009. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.

Deferred Financing Costs and Other Assets—Net

At December 31, 2011, we had intangible assets from continuing operations consisting of $3.3 million, which is primarily made up of loan costs that are amortized using the straight line method over their respective estimated lives, which is, on average, three to five years. We amortize any costs incurred to renew or extend the terms of existing intangible assets over the contract term or estimated useful life, as applicable, using the straight-line method. For the years ended December 31, 2011, 2010, and 2009, we recorded amortization expense from continuing operations of $0.8 million, $0.5 million and $0.4 million, respectively. The aggregate estimated annual amortization expense from continuing operations for each of the next five calendar years is as follows: 2012—$1.2 million; 2013—$0.8 million; 2014—$0.7 million; 2015—$0.5; and 2016—$0.1.

The following is a summary of intangible assets at the dates indicated:

	December 31, 2011 (in  thousands)		December 31, 2010 (in  thousands)
Intangible – Gross	$	5,637	$	2,920

F-16

Accumulated Amortization		(2,329	)		(1,526	)
Intangible Assets – Net	$	3,308		$	1,394

Specific to our loan costs, we have incurred gross debt issuance costs of approximately $4.1 million, $1.4 million and $0.7 million for the years ended December 31, 2011, 2010 and 2009, respectively, which are presented net of accumulated amortization of $1.1 million, $0.6 million and $0.4 million, respectively. All intangible assets, including loan costs, at December 31, 2011 are included in Deferred Financing Costs and Other Assets—Net on the Consolidated Balance Sheets.

Future Abandonment Cost

Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.

Accretion expense from continuing operations during the years ended December 31, 2011, 2010 and 2009 totaled approximately $1.5 million, $1.7 million and $1.5 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells.

	December 31, 2011 ($ in Thousands)			December 31, 2010 ($ in Thousands)
Beginning Balance	$	17,222		$	16,143
Asset Retirement Obligation Incurred		235			196
Asset Retirement Obligation Settled		(266	)		(796	)
Asset Retirement Obligation Cancelled or Sold Well Properties		0			(25	)
Asset Retirement Obligation Accretion Expense		1,479			1,704
Total Asset Retirement Obligation	$	18,670		$	17,222

Revenue Recognition

Oil and natural gas revenue is recognized when the oil or natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil and NGL sales, title is transferred

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to the purchaser when the oil or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil or gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil, NGL and natural gas production is at its applicable field gathering system. We do not currently participate in any gas-balancing arrangements. We do not recognize revenue for oil and NGL production held in stock tanks before delivery to the purchaser.

To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the Consolidated Balance Sheets and Oil, Natural Gas and NGL Sales on the Statements of Operations.

Derivative Instruments

We use put and call options (collars), fixed rate swap contracts, swaptions, puts and put spreads to manage price risks in connection with the sale of oil and natural gas. We have also, in the past, used interest rate swap agreements to manage interest rate risks associated with our variable rate credit facility. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third-parties. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2009, 2010 and 2011 we did not have any derivative instruments designated for hedge accounting.

For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil and natural gas production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings. For additional information on our derivative

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instruments, see Note 12, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.

Income Taxes

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to other temporary differences.

Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted tax rate. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized.

This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position.

The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets.

We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 13, Income Taxes, to our Consolidated Financial Statements). Our policy is to recognize interest and penalties on any unrecognized tax benefits in interest expense and general and administrative expense, respectively.

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Stock-based Compensation

We recognize in the Consolidated Financial Statements the cost of employee and non-employee director services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of the grant.

The benefits associated with the tax deductions in excess of recognized compensation cost are reported as a financing cash flow when realized. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 17, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). Stock appreciation rights are classified as a liability and are re-measured at fair value each reporting period.

Earnings per Share

Earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding. Diluted earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding during the period, including any potentially dilutive outstanding securities, such as options and warrants. The potentially dilutive outstanding securities are calculated using the treasury stock method. At December 31, 2011, we had 44,859,220 common shares outstanding, 698,327 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. For additional information, see Note 14, Earnings per Common Share, to our Consolidated Financial Statements.

Capital Leases

As a lessee, we determine if a lease is a capital lease if it meets one of four of the following criteria:

• The ownership of the leased property transfers to us by the end of the lease term, or shortly thereafter, in exchange for the payment of a nominal fee.

• The lease contains a bargain purchase option.

• The lease term is equal to 75% or more of the estimated economic life of the leased property.

• The present value at the beginning of the lease term of the minimum lease payments, excluding that portion of the payments representing executor costs such as insurance, maintenance, and taxes to be paid by the lessor, including any profit thereon, equals or exceeds 90% of the excess of the fair value of the leased property to the lessor at the lease inception over any related investment tax credit retained by the lessor and expected to be

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realized by the lessor.

As of December 31, 2011 we had capital leases on field vehicles being used in our Illinois and Appalachian Basin operations. We recorded these leases as Other Property and Equipment on our Consolidated Balance Sheets in the amount of $2.3 million as of December 31, 2011, and $1.8 million as of December 31, 2010. The remaining obligation to be paid on these leases totaled approximately $0.5 million, of which $0.1 was classified as Senior Secured Line of Credit and Long-Term Debt under Long-Term Liabilities and $0.4 was classified as Accounts Payable under Current Liabilities on our Consolidated Balance Sheets, all of which is expected to be paid by 2015. We recorded approximately $0.4 million, $0.2 million and $48,000 of amortization on these vehicles, classified as DD&A on our Consolidated Statements of Operations, for the years ended December 31, 2011, 2010 and 2009, respectively.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities . ASU 2011-11 provides new disclosure requirements related to offsetting arrangements to allow investors to better compare financial statements prepared in accordance with IFRS and U.S. GAAP. The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods, including retrospective application for all comparative periods presented. Although we currently are not engaged in any arrangements that would be effected by these disclosure requirements, we believe that ASU 2011-11 may have a material impact on future disclosures pending our entrance into an offsetting arrangement.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS . ASU 2011-04 generally provides a uniform framework for fair value measurements and related disclosures between GAAP and International Financial Reporting Standards (“IFRS”). Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements, quantitative information about unobservable inputs used, a description of the valuation process used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a nonfinancial asset that is different from the asset’s highest and best use, the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required, the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosures of all transfers between Level 1 and Level 2 of the fair value hierarchy. This update is effective for annual and interim periods beginning on or after December 31, 2011. We adopted ASU 2011-04 on January 1, 2012, with no material impact.

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In December 2010, the FASB issued ASU 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (“ASU 2010-29”). The amendments to the codification clarify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Additionally, the supplemental pro forma disclosures under Topic 805 have been expanded to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments in ASU 2010-29 are effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Although we have not entered into any significant business combinations in our recent history, we believe that ASU 2010-29 may have a material impact on future disclosures depending on the size and nature of any future business combinations that we may enter into. We adopted ASU 2010-29 on January 1, 2011.

3. BUSINESS SEGMENT INFORMATION

We have changed the structure of our internal organization causing a change in the composition of our segments as a result of meeting the qualitative and quantitative requirements of ASC 280,Segment Reporting. Accordingly, we have restated the items of segment information for all periods presented to reflect this change in our internal organization. Business segment information was not reported in prior years.

We have two principal reportable segments, which are segregated based on the products and services that each provide: (a) exploration and production, and (b) field services. Our exploration and production segment engages in the exploration, acquisition, development and production of oil, natural gas and natural gas liquids. Our field services segment operates and manages water sourcing, water transfer and water disposal services, primarily in the Appalachian Basin.

We evaluate the performance of our business segments based on net income (loss) from continuing operations, before income taxes. All intercompany transactions, including those between consolidated business segments, are eliminated in consolidation. Summarized financial information concerning our segments is shown in the following table for 2011 and 2010 (our field services segment did not exist prior to 2010) (in thousands):

For the Year Ended December 31, 2011	Exploration and Production		Field Services			Intercompany Eliminations			Consolidated Total
Revenues	$	112,088	$	3,546		$	(1,028	)	$	114,606
Inter-Segment Revenues		0		(1,028	)		1,028			0
Total Revenues		112,088		2,518			0			114,606
Depreciation, Depletion and Amortization		28,175		186			0			28,361
Impairment Expense		14,316		315			0			14,631

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Other Operating Expenses(a)		59,917			3,169			(756	)		62,330
Interest Expense		2,018			1			0			2,019
Other (Income) Expense(b)		(19,021	)		(100	)		35			(19,086	)
Income (Loss) From Continuing Operations, Before Income Taxes	$	26,683		$	(1,053	)	$	721		$	26,351
Total Assets	$	594,545		$	7,143		$	(137	)	$	601,551
Expenditures for Long-Lived Assets	$	269,823		$	5,571		$	0		$	275,394
Equity Method Investments	$	41,683		$	0		$	0		$	41,683
For the Year Ended December 31, 2010
Revenues	$	67,397		$	1,718		$	(352	)	$	68,763
Inter-Segment Revenues		0			(352	)		352			0
Total Revenues		67,397			1,366			0			68,763
Depreciation, Depletion and Amortization		21,660			146			0			21,806
Impairment Expense		8,424			439			0			8,863
Other Operating Expenses(a)		27,820			1,538			(37	)		29,321
Interest Expense		1,070			0			0			1,070
Other (Income) Expense(b)		(5,602	)		0			0			(5,602	)
Income (Loss) From Continuing Operations, Before Income Taxes	$	14,025		$	(757	)	$	37		$	13,305
Total Assets	$	405,066		$	2,019		$	0		$	407,085
Expenditures for Long-Lived Assets	$	149,075		$	1,323		$	0		$	150,398
Equity Method Investments	$	18,399		$	0		$	0		$	18,399

(a) Includes the following expenses: production and lease operating expense, general and administrative expense, (gain) loss on disposal of assets, exploration expense, field services operating expenses and other operating expense.

(b) Includes the following expenses: interest income, gain (loss) on derivative, net, other income (expense) and gain (loss) on equity method investments.

4. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS

Acquisitions

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We have made no significant acquisitions for the years ended December 31, 2011, 2010 and 2009.

Dispositions

Sumitomo Joint Venture

On September 30, 2010, we entered into a joint venture transaction with Sumitomo Corporation (“Sumitomo”). In Butler County, Pennsylvania we sold a 15% non-operated interest in approximately 40,700 net acres for approximately $30.6 million in cash at closing and $30.6 million in the form of a drilling carry of 80% of our drilling and completion costs in the area. Pursuant to the Participation and Exploration Agreement (the “Sumitomo PEA”), Sumitomo agreed to pay all of the costs to lease approximately 9,000 net acres in the Butler County Area of Mutual Interest (“AMI”) (the “Phase I Leasing”), and to pay to us a leasing management fee of $1,000 per net acre during the Phase I Leasing. The Phase I Leasing and drilling carry for Butler County were completed during the first quarter of 2011, resulting in final ownership percentages of 70% to us and 30% to Sumitomo. The cost of future leasing activities will be shared on a 70/30 basis, with Sumitomo paying to us a management fee of $150 per net acre acquired. In addition to the sale of undeveloped acreage, we also sold to Sumitomo 30% of our interests in 20 Marcellus Shale wells within the Butler County area and 30% of our interest in Keystone Midstream Services, LLC (“Keystone Midstream”) (for additional information on Keystone Midstream, see Note 6, Consolidated Subsidiaries, and Note 7, Equity Method Investments, to our Consolidated Financial Statements).

In our Marcellus Shale joint venture project areas with WPX Energy San Juan, LLC (formerly known as Williams Production Company, LLC) and Williams Production Appalachia, LLC (collectively, “Williams”), which is discussed below, we sold to Sumitomo 20% of our interests in 23,500 net acres for approximately $19.0 million in cash at closing and $19.0 million in the form of a drilling carry of 80% of our drilling and completion costs in the areas. In addition, we sold 20% of our interests in 19 Marcellus Shale wells located in the Williams joint venture areas and 20% of our interest in RW Gathering, LLC (“RW Gathering”) (for additional information on RW Gathering, see Note 7, Equity Method Investments, to our Consolidated Financial Statements).

In addition to the areas above, we sold to Sumitomo 50% of our interests in approximately 4,500 net acres in Fayette and Centre Counties, Pennsylvania for $9.2 million in cash at closing and $9.2 million in the form of a drilling carry of 80% of our drilling and completion costs. Pursuant to the Sumitomo PEA, the drilling carry for these areas was to be applied, at our discretion, to drilling and completion costs attributable to either the Butler County or Williams joint venture areas. As of December 31, 2011, there was no remaining drilling carries with Sumitomo.

At closing, we received approximately $99.5 million in cash, which included a reimbursement for leasing expenses incurred subsequent to the effective date of September 1, 2010, in the amount of approximately $7.6 million. Additionally, the cash payment included a reimbursement for drilling related expenses incurred subsequent to the effective date in the amount of approximately $7.5 million, which was applied against the drilling carry. Pursuant to industry rules, we do not make any accounting for the carried amounts paid on our behalf by Sumitomo. We recognized approximately a $16.5 million gain on

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the Sumitomo transaction which is classified as (Gain) Loss on Disposal of Asset on our Consolidated Statement of Operations.

Williams Joint Venture

In the second quarter of 2009, we entered into a Participation and Exploration Agreement (the “Williams PEA”) with Williams that was effective as of May 5, 2009. Under the terms and conditions of the Williams PEA, Williams acquired, through a “drill-to-earn” structure, a 50% working interest in certain oil and gas leases covering approximately 43,672 net acres in Centre, Clearfield and Westmoreland Counties, Pennsylvania (the “Project Area”). The Williams PEA effectively provided that, for Williams to earn its 50% interest in the Project Area, Williams would bear 90% of all costs and expenses incurred in the drilling and completion of all wells jointly drilled in the Project Area until such time as Williams had invested approximately $74.0 million (approximately $33.0 million on behalf of us and $41.0 million for Williams’ 50% share of the wells). The Williams PEA represents a pooling of assets in a joint undertaking by us and Williams and, therefore, we do not make any accounting for the $33.0 million of carried interest paid on our behalf by Williams. As of December 31, 2010, Williams had completed its carry obligation and acquired a 50% working interest in the leases within the Project Area, and the parties will share all costs of the joint venture operations within an area of mutual interest (including the Project Area) in accordance with their participating interests, which are expected to be on a 50 (Williams)/40 (Rex)/10 (Sumitomo) basis.

In accordance with the terms of the Williams PEA, Williams reimbursed us for approximately $3.1 million for Williams’ share of certain expenses incurred in the acquisition and development of oil and gas leases within the Project Area that we had previously paid. Williams became the operator of the Project Area on January 1, 2010.

Other

In the first quarter of 2009, we completed the sale of certain oil and gas leases, wells and related assets located primarily in the Permian Basin in the states of Texas and New Mexico for net proceeds of approximately $17.3 million and recorded a loss of $0.4 million. We have reflected the results of these divested operations as discontinued operations rather than a component of continuing operations. For additional information, see Note 5, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

5. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado, and we have engaged an advisor to assist with the marketing efforts. The assets are available for immediate sale pending normal due diligence incurred during the course of business, with a sale expected within one year. The recording of Depreciation, Depletion, Amortization and Accretion (“DD&A”) expense related to our DJ Basin assets ceased in December 2011. We evaluated the value, less cost to sell, of our DJ Basin assets, as of December 31,

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2011, and determined that the fair value of our assets was greater than the carrying amount of the assets. Therefore no adjustment to the carrying value was required. Upon the completion of a sale, we will have no continuing activities in the DJ Basin or continuing cash flows from this region.

These assets have been classified as Assets Held for Sale on our Balance Sheet as of December 31, 2011 and December 31, 2010, and the results of operations are reflected in Discontinued Operations in our Consolidated Statements of Operations. We incurred direct wage costs in the amount of $0.2 million associated with the sale of our DJ Basin assets, which was recorded in Discontinued Operations on our Consolidated Statement of Operations. We have included $24.8 million and $47.9 million of net assets located in the DJ Basin as Assets Held for Sale on our Consolidated Balance Sheets as of December 31, 2011 and 2010, respectively. We have included approximately $1.6 and $4.7 million of liabilities as Liabilities Related to Assets Held for Sale on our Consolidated Balance Sheets as of December 31, 2011 and 2010, respectively. These liabilities primarily relate to Accounts Payable and Accrued Expenses.

On March 24, 2009, we completed the sale of certain oil and gas leases, wells and related assets predominantly located in the Permian Basin in the states of Texas and New Mexico. We received net cash proceeds of approximately $17.3 million, which was able to be adjusted by certain post-closing adjustments, plus the assumption of certain liabilities, based on an effective date of October 1, 2008. Upon closing of the sale, we used the proceeds to pay down our long-term borrowings on our Senior Credit Facility.

Pursuant to the accounting rules for discontinued operations, these assets were classified as Assets Held for Sale on our Balance Sheet as of December 31, 2009, and results of operations are reflected in Discontinued Operations in our Consolidated Statements of Operations. We recorded a loss on sale of assets of approximately $0.4 million in our Consolidated Statement of Operations. Upon closing of the sale, we recorded severance wages in Discontinued Operations of approximately $0.2 million for our former employees in the Southwest Region.

Summarized financial information for Discontinued Operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. As of December 31, 2011 and 2010, we did not have any assets or liabilities classified as held for sale related to the Permian Basin.

	December 31, ($ in thousands)
	2011		2010		2009
Revenues:
Oil and Gas Sales	$	556	$	0	$	193
Total Operating Revenue		556		0		193
Costs and Expenses:

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Production and Lease Operating Expense		493			0			237
General and Administrative Expense		1,745			782			(97	)
Exploration Expense		33,812			2,664			0
Impairment Expense		13,177			0			0
Depreciation, Depletion, Amortization and Accretion		85			1			0
Other Operating Expense		1			0			0
Gain from Derivatives, net		0			0			(558	)
Interest Expense		1			0			0
Other Expense		1			0			0
Total Costs and Expenses		49,315			3,447			(418	)
Income (Loss) from Discontinued Operations Before Income Taxes		(48,759	)		(3,447	)		611
Income Tax (Expense) Benefit		15,302			1,425			(288	)
Income (Loss) from Discontinued Operations, net of taxes	$	(33,457	)	$	(2,022	)	$	323
Production:
Crude Oil (Bbls)		6,939			0			7,507
Natural Gas (Mcf)		0			0			61,661
Total (Mcfe)		41,634			0			106,703

6. CONSOLIDATED SUBSIDIARIES

Water Solutions Holdings

In November 2009, we entered into a limited liability agreement with Sand Hills Management, LLC (“Sand Hills”) to form Water Solutions Holdings, LLC (“Water Solutions”) for the purpose of acquiring, managing and operating water treatment, disposal and transportation facilities that are designed to treat, dispose or transport brine and fresh waters used and produced in oil and gas well development activities. The members of Water Solutions are Rex Energy Corporation, which owns an 80% membership interest, and Sand Hills, which owns a 20% membership interest and serves as the operator of the entity.

We fully consolidated the accounts of Water Solutions in our financial statements and accounted for the 20% equity interest owned by Sand Hills as a noncontrolling interest. As of December 31, 2011 and 2010, has recourse to our general credit. Water Solutions is financed through cash contributions from its members. We contributed approximately $20,000 in cash in 2011 and approximately $1.1 million in cash in 2010 to fund the operations of Water Solutions. Business generating activities for this entity did not exist prior to 2010.

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NorthStar #3, LLC

In August 2011, our wholly owned subsidiary, R.E. Gas Development, LLC (“R.E. Gas”) and NorthStar Water Management (“NorthStar”) formed NorthStar #3, LLC (“NorthStar #3”) to construct, own and operate a water disposal well in Mahoning County, Ohio. At December 31, 2011, R.E. Gas owned a 51% membership interest in NorthStar #3 and the remaining 49% membership interest was owned by NorthStar, which also serves as the operator of the entity. To supplement the operations of NorthStar #3, the entity entered into a promissory note with us. As of December 31, 2011, the amount owed to us under the promissory note was $4.9 million (for additional information see Note 10, Related Party Transactions, to our Consolidated Financial Statements).

A variable interest entity (“VIE”) is an entity that by design has insufficient equity to permit it to finance its activities without additional subordinated financial support or equity holders that lack the characteristics of a controlling financial interest. Based on these factors we have determined NorthStar #3 to be a VIE.

We are considered the primary beneficiary of the entity and have consolidated the financial results. To be considered the primary beneficiary, a member must have the power to direct the activities that most significantly impact the entity’s performance and have a significant variable interest that carries with it the obligation to absorb the losses or the right to receive benefits. The activities that most significantly impact the entity’s economic performance relate to the drilling of a successful disposal well with ample capacity and the ongoing operation of the well. Per the membership agreement, we hold a first right of refusal on all capacity rights for the disposal well, giving us the ability to make decisions regarding the operation and capacity of the well based on market conditions and, thus, the ability to direct the activities that most significantly impact the economic performance of the entity. We hold a significant variable interest in the entity in the form of our 51% membership interest and the $4.9 million promissory note. We have no recourse to recover the amount of the promissory note in the event that the disposal well is unsuccessful, leaving us with the obligation to absorb the losses. Upon success of the disposal well, we will initially have the right to approximately 87.3% of the available cash at the end of the period which covers the repayment of the note and our membership interest.

As of December 31, 2011, we contributed $490 in capital to NorthStar #3. The carrying amount and classifications of NorthStar #3 assets and liabilities as of December 31, 2011 are as follows, with no restrictions or obligations to use certain assets to settle associated liabilities (NorthStar #3 did not exist as of December 31, 2010):

	December 31, 2011 (in thousands)
ASSETS
Cash and Cash Equivalents	$	10

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Wells and Facilities in Progress		5,059
Total Assets	$	5,069
LIABILITIES
Accounts Payable	$	134
Note Payable		4,935
Total Liabilities	$	5,069

7. EQUITY METHOD INVESTMENTS

RW Gathering

Pursuant to the terms of the Williams PEA, we and Williams agreed to form RW Gathering, LLC (“RW Gathering”), a Delaware limited liability company, to own any gas-gathering assets which we agreed to jointly construct in order to facilitate the development of our Project Area. The initial members of RW Gathering were Williams and us, each owning an equal interest in the company. On September 30, 2010, pursuant to the Sumitomo PEA, we sold 20% of our interest in RW Gathering to Sumitomo, decreasing our ownership in RW Gathering to 40% (for additional information, see Note 4, Business and Oil and Gas Property Acquisitions and Dispositions , to our Consolidated Financial Statements). As of January 1, 2010, Williams became the manager of RW Gathering.

We recorded our investment in RW Gathering of approximately $15.7 million and $6.4 million as of December 31, 2011 and 2010, respectively, on our Consolidated Balance Sheets as Equity Method Investments. During 2011, we contributed approximately $9.7 million in cash to RW Gathering to support current pipeline and gathering line construction, compared to $5.6 million during the same period in 2010. RW Gathering recorded net losses from continuing operations of $0.4 million and $0.1 million for the years ended December 31, 2011 and 2010, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and DD&A expense. Our share of the net loss from continuing operations is recorded on the Statements of Operations as Loss on Equity Method Investments.

When evaluating our Equity Method Investments for impairment we review our ability to recover the carrying amount of such investments or the entity’s ability to sustain earnings that justify its carrying amount. In the case of RW Gathering, the nature of its assets is such that under normal circumstances an entity would capitalize and evaluate the assets as a part of its producing well properties. Therefore, our ability to recover the carrying amount of our investment lies in the value of our producing well assets that

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utilize these gathering systems. As of December 31, 2011, we determined that we had the ability to recover the carrying amount of our investment in RW Gathering.

Keystone Midstream

On September 30, 2010, we sold 30% of our interest in Keystone Midstream Services, LLC (“Keystone Midstream”) to Sumitomo, decreasing our ownership of the entity to 28% and triggering a re-evaluation of the consolidation analysis. Due to our decreased ownership in Keystone Midstream and our decreased ownership of the Butler County, Pennsylvania assets to be serviced by Keystone Midstream (see Note 4, Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements); we no longer have the power to direct the activities that most significantly impact the entity’s economic performance. Thus, we are no longer considered the primary beneficiary of Keystone Midstream and have deconsolidated the operations as of September 1, 2010, the effective date of the sale.

As of September 1, 2010, we accounted for our 28% ownership interest in Keystone Midstream via the equity method. Prior to September 1, 2010, Keystone Midstream was a consolidated VIE. Under the equity method, we recorded our investment in Keystone Midstream of approximately $26.0 million and $12.0 million as of December 31, 2011 and 2010, respectively, on our Consolidated Balance Sheet as Equity Method Investments. In 2011 and 2010, we contributed approximately $13.5 million and $9.6 million, respectively, to Keystone Midstream primarily support the construction of cryogenic gas processing plants. Keystone Midstream recorded net income from continuing operations of $1.6 million for the year ended December 31, 2011, and a net loss of $0.5 million for the four month period ended December 31, 2010.

Prior to September 1, 2010, we consolidated the operations of Keystone Midstream, where the noncontrolling interest’s share of net loss was recorded as Net Loss Attributable to Noncontrolling Interests. Subsequent to September 1, 2010, we record our share of net losses related to Keystone Midstream as Loss on Equity Method Investments on our Consolidated Statement of Operations. Our share of losses incurred to date under the equity method of accounting are primarily due to project management costs, general and administrative expenses, and DD&A expenses and totaled approximately $0.5 million and $0.1 million for the years ended December 31, 2011 and 2010, respectively.

When evaluating our Equity Method Investments for impairment we review our ability to recover the carrying amount of such investments or the entity’s ability to sustain earnings that justify its carrying amount. In the case of Keystone Midstream, the entity has justified its ability to sustain earnings that justify its carrying amount through the capacity reservation fee (see Note 9, Commitments and Contingencies, to our Consolidated Financial Statements). The capacity reservation fee provides guaranteed cash flows to the equity group.

8. CONCENTRATIONS OF CREDIT RISK

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At times during the years ended December 31, 2011 and 2010, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations.

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with four high-quality counterparties. Our counterparties are investment grade financial institutions, and lenders in our Senior Credit Facility. We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled settlement date. For additional information, see Note 2, Summary of Significant Accounting Policies, and Note 12, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At December 31, 2011, we carried approximately $13.6 million in production receivables, of which approximately $12.9 million were production receivables due from three purchasers. At December 31, 2010, we carried approximately $8.1 million in production receivable, of which approximately $7.3 million were production receivables due from five purchasers. We believe the growth in our Appalachian estimated proved reserves will help us to minimize our future risks by diversifying our ratio of oil and gas sales as well as the quantity of purchasers.

9. COMMITMENTS AND CONTINGENCIES

Legal Reserves

At December 31, 2011, our Consolidated Balance Sheet included approximately $0.1 million in reserve for the legal matters referenced in Note 25— Litigation. At December 31, 2010, our Consolidated Balance Sheet included $0.2 million in reserve for various legal proceedings. The accrual of reserves for legal matters is included in Accrued Expenses on the Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that we could incur additional loss, the amount of which is not currently estimable, in excess of the amounts currently accrued with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed current accruals by an amount that would have a material adverse effect on our consolidated financial position or results of operations, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

Acreage Bonus Payments

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At December 31, 2011, we had installment payment commitments on mineral interests that were previously leased in the amount of $1.2 million. All of these commitments are expected to be paid in 2012 and have been classified as Accrued Expenses on our Consolidated Balance Sheet. At December 31, 2010, our liability for installment payment commitments on mineral interests totaled approximately $5.2 million, with $1.7 million classified as Accrued Expenses and $3.5 million classified as Other Deposits and Liabilities on our Consolidated Balance Sheet.

Environmental

Due to the nature of the natural gas and oil business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate salaries and wages cost of employees who are expected to devote a significant amount of time directly to any remediation effort.

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Except for contingent liabilities associated with the consent decree with the U.S. EPA relating to alleged H ₂ S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

We have posted $0.8 million, at December 31, 2011 and December 31, 2010, in various letters of credit to secure our drilling and related operations.

Lease Commitments

At December 31, 2011 we have lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $0.4 million, $0.3 million and $0.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands).

2012	$	497
2013		548

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2014		104
2015		44
2016		0
Thereafter		0
Total	$	1,193

Capacity Reservation

In connection with the formation of Keystone Midstream (see Note 7, Equity Method Investments, to our Consolidated Financial Statements), we entered into a capacity reservation arrangement with Keystone Midstream to ensure sufficient capacity at the Sarsen cryogenic gas processing plant to process our produced natural gas. Under the terms of the arrangement, we reserved 14 Mmcfe of net processing capacity per day for the first year of operations, effective in February 2011, and 28 Mmcfe of net processing capacity for the subsequent nine years of operation, or through January 2020. If we do not meet our capacity reservation volumes, we are obligated to pay $0.30/Mcfe per day for the difference between actual processed volumes and the reservation volume. In the event that we do not process any gas through the cryogenic gas processing plant we may be obligated to pay approximately $2.9 million in 2012, $3.1 million for each year from 2013 through 2019, and $0.3 million in 2020. As of December 31, 2011, our production has increased to levels maximizing the current plant capacity.

Operational Commitments

Pursuant to agreements reached during the fourth quarter of 2010 and the first quarter of 2011, we have contracted drilling rig services on two rigs to support our Butler County, Pennsylvania operations. The minimum cost to retain these rigs would require payments of approximately $1.1 million in 2012 and $0.1 million in 2013, which is consistent with our 70% working interest in this project area. In addition, during the first quarter of 2011 we came to terms on contracted completion services in Butler County,

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Pennsylvania. The minimum cost to retain the completion services is approximately $8.4 million in 2012 and $2.1 million in 2013, which is consistent with our 70% working interest in this project area.

Natural Gas Gathering, Processing and Sales Agreements

Under a natural gas sales agreement with BP Energy Company (“BP Energy”), we have agreed to supply natural gas to BP Energy at certain delivery points in Pennsylvania with a termination date expected to be December 31, 2022, unless terminated earlier under certain conditions specified in the sales agreement. During the term of the sales agreement, we are obligated to provide to BP Energy, and BP Energy is obligated to purchase from us, a minimum monthly volume of natural gas equivalent to 17,500 MMBtu of natural gas per day from March 1, 2012 to December 31, 2012 and 59,500 MMBtu per day after January 1, 2013. On all volumes delivered, and on any shortfalls between volumes delivered and the minimum monthly quantity, we are obligated to pay a marketing fee and a demand charge. In connection with the entry into the sales agreement, we concurrently entered into a guaranty agreement whereby we have guaranteed the payment of obligations under the sales agreement up to a maximum of $50.0 million.

During the fourth quarter of 2011, we entered into gathering and processing agreements with Dominion East Ohio (“Dominion East”) and Dominion Natrium, LLC (“Dominion Natrium”), respectively, to transport and process anticipated natural gas and natural gas liquid production in Ohio. Under the gathering agreement, we have agreed to supply natural gas at certain delivery points in Ohio for a 10-year primary term, which is anticipated to begin on October 1, 2012. During the term of the gathering agreement, Dominion East is obligated to transport a maximum of 15,000 mcf per day and we are obligated to pay a fee based on the volumes transported. Under the processing agreement, we have agreed to supply natural gas at Dominion Natrium’s processing and fractionation facility in Natrium, West Virginia for a 10-year primary term, which is anticipated to begin on December 1, 2012. During the term of the processing agreement, Dominion Natrium is obligated to process a maximum of 15,000 mcf per day and we are obligated to pay a reservation fee.

In coordination with the aforementioned gathering and processing agreements, we have entered into an additional natural gas sales agreement with BP Energy, where we are obligated to sell, and BP Energy is obligated to purchase, 14,000 MMBtu per day of natural gas, for which we will pay a marketing fee and demand charge. The effective date of the sales agreement is expected to be no sooner than November 1, 2014 and will last until December 31, 2022.

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Minimum net obligations under these sales, gathering and transportation agreements for the next five years ($ in thousands):

	BP Energy		Dominion East(a)		Dominion Natrium(a)		Total
2012	$	624	$	345	$	195	$	1,164
2013		2,531		1,369		2,300		6,200
2014		2,673		1,369		2,300		6,342
2015		3,382		1,369		2,300		7,051
2016		3,382		1,369		2,300		7,051
Thereafter		21,143		7,868		13,602		42,613
Total	$	33,735	$	13,689	$	22,997	$	70,421

(a) Assumes 100% working interest, actual working interest could be materially different as drilling units are formed.

Other

In addition to the asset retirement obligation discussed in Note 2, Summary of Significant Accounting Policies, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. Such amounts, totaling $0.3 million, are included in Other Deposits and Liabilities at December 31, 2011 and December 31, 2010, respectively.

10. RELATED PARTY TRANSACTIONS

Aircraft Services

We currently have an oral month-to-month agreement with Charlie Brown Air Corp. (“Charlie Brown”), a New York corporation owned by Lance T. Shaner, our Chairman, regarding the use of two airplanes owned by Charlie Brown. Under our agreement with Charlie Brown, we pay a monthly fee for the right to use the airplanes equal to our percentage (based upon the total number of hours of use of the airplanes by us) of the monthly fixed costs for the airplanes, plus a variable per hour flight rate that ranges from $400 to $1,850 per hour. In September 2010, we purchased an undivided 50% interest in one of these airplanes, a Cessna model 550 from Charlie Brown for approximately $0.6 million. In April 2011, we purchased the remaining 50% interest in this aircraft for approximately $0.6 million. The purchase of the aircraft has been recorded as Other Property and Equipment on our Consolidated Balance Sheets. For the years ended December 31, 2011, 2010 and 2009, we paid Charlie Brown $0.2 million, $0.4 million and $0.1 million, respectively, for the use of the aircrafts, including the variable per hour cost in addition to pilots fees, maintenance, hangar rental and other miscellaneous expenses.

We own a 25% membership interest in Charlie Brown Air II, LLC (“Charlie Brown II”). Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Mr. Lance T. Shaner (“Shaner Hotel”), and an unrelated third party each own 25% and 50%, respectively, in Charlie Brown II, which owns and operates an Eclipse 500 aircraft, which was purchased for approximately $1.7 million.

Charlie Brown II has a loan from Graystone Bank to purchase the aircraft that was originally $1.5 million at its inception in June 2007. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan required payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II has been required to make monthly payments of principal and interest

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utilizing an amortization period of 180 months. The Company and Shaner Hotel each guarantee up to twenty five percent, or $0.4 million, of the principal balance of the loan. The balance of this loan as of December 31, 2011 and 2010 was approximately $0.5 million and $1.4 million, respectively. For the years ended December 31, 2011, 2010 and 2009, we paid Charlie Brown II approximately $0.2 million each year, respectively, for loan interest, services rendered and retainer fees.

The business affairs of Charlie Brown Air II, LLC are managed by three members, appointed by each of its three owners. We have designated Thomas C. Stabley, our Chief Executive Officer, as the manager representing our membership interest. Actions of the company must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance with the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of the company, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown Air II, LLC, require the written consent of all managers. The consent of managers is also required before the company may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the company’s assets or sell the airplane owned by the company. In the event that the members are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the company.

RW Gathering, LLC

Pursuant to the terms of the Williams PEA, we and Williams agreed to form RW Gathering to own any gas-gathering assets which we agreed to jointly construct in order to facilitate the development of our Project Area (see Note 7, Equity Method Investments, to our Consolidated Financial Statements). For the years ended December 31, 2011 and 2010, we incurred approximately $0.8 million and $0.2 million, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of December 31, 2011 and 2010, there were no receivables or payables in relation to RW Gathering due to or from us.

Keystone Midstream

We incurred approximately $4.6 million and $0.3 million in transportation and processing expenses that were charged to us from Keystone Midstream during 2011 and 2010, respectively (see Note 7, Equity Method Investments , to our Consolidated Financial Statements). Prior to September 1, 2010, charges incurred for transportation were eliminated in consolidation. Subsequent to August 31, 2010, such transportation charges are recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations. As of December 31, 2011, we had Accrued Expenses due to Keystone Midstream of approximately $0.5 million, which was inclusive of transportation and processing expenses incurred during December 2011. As of December 31, 2010, we had Accrued Expenses due to Keystone Midstream of approximately $1.3 million, which was comprised of $0.1 million in transportation and processing expenses incurred during the fourth quarter 2010 and $1.2 million in expenses due from us to

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fund the acceleration of the Sarsen cryogenic gas processing plant construction. There were no related party expenses or amounts due to or from us to Keystone Midstream prior to January 1, 2010.

Water Solutions

We incurred approximately $1.6 million and $0.4 million in water transfer and water purification expenses that were charged to us from Water Solutions during 2011 and 2010, respectively (see Note 6,Consolidated Subsidiaries, to our Consolidated Financial Statements). We have eliminated these charges in consolidation. As of December 31, 2011, we had payables of approximately $0.3 million to Water Solutions for work performed during the period, which were eliminated in consolidation. As of December 31, 2010, we did not have any payables due to Water Solutions.

NorthStar #3, LLC

During 2011, we paid approximately $4.9 million in expenses related to the drilling of a water disposal well on behalf of NorthStar #3 (see Note 6, Consolidated Subsidiaries, to our Consolidated Financial Statements). This amount has been recorded in a promissory note due to us from NorthStar #3, bearing 5% interest. The promissory note has been eliminated in consolidation, while the cost of the well has been recorded as Wells and Facilities in Progress on our Consolidated Balance Sheet. As of December 31, 2011, there were no amounts due to NorthStar #3 or due to us from NorthStar #3 with exception to the promissory note. NorthStar #3 did not exist prior to 2011.

11. LONG-TERM DEBT

Senior Credit Facility

We maintain a revolving credit facility evidenced by the Credit Agreement, dated September 28, 2007, with KeyBank, as Administrative Agent; Royal Bank of Canada, as Syndication Agent; Sovereign Bank, as Documentation Agent; and lenders from time to time parties thereto (as amended from time to time, the “Senior Credit Facility”). Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. The borrowing base under the Senior Credit Facility is currently $255.0 million; however, the revolving credit facility may be increased up to $500 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. The Senior Credit Facility provides that the borrowing base will be re-determined semi-annually by the lenders, in good faith, based on, among other things, reports regarding our oil and gas reserves attributable to our oil and gas properties, together with a projection of related production and future net income, taxes, operating expenses and capital expenditures. We may, or the Administrative Agent at the direction of a majority of the lenders may, each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In

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addition, we may request interim borrowing base re-determinations upon our proposed acquisition of proved developed producing oil and gas reserves with a purchase price for such reserves greater than 10% of the then borrowing base. As of December 31, 2011, loans made under the Senior Credit Facility were set to mature on September 28, 2015. In certain circumstances, we may be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months. As of December 31, 2011, we had $175.0 million drawn on the Senior Credit Facility as compared to $10.0 million at December 31, 2010.

Borrowings under the Senior Credit Facility bear interest, at our election, at the Adjusted LIBOR or the Alternative Base Rate (as defined below) plus, in each case an applicable per annum margin. The applicable per annum margin is determined based upon our total borrowing base utilization percentage in accordance with a pricing grid. The applicable per annum margin ranges from 1.75% to 2.75% for Eurodollar loans and .50% to 1.50% for ABR loans. The Adjusted Base Rate is equal to the greater of: (i) KeyBank’s announced prime rate; (ii) the federal funds effective rate from time to time plus¹ / 2 of 1%; and (iii) LIBOR plus 1.25%. Our commitment fee is also dependent on our total borrowing base utilization percentage and is determined based upon an applicable per annum margin which ranges from 0.375% to 0.50%.

Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million and 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate.

The Senior Credit Facility contains covenants that restrict our ability to, among other things, materially change our business; approve and distribute dividends; enter into transactions with affiliates; create or acquire additional subsidiaries; incur indebtedness; sell assets; make loans to others; make investments; enter into mergers; incur liens; and enter into agreements regarding swap and other derivative transactions (for further information, see Note 2, Summary of Significant Accounting Policies, Note 8, Concentrations of Credit Risk, and Note 12,Fair Value of Financial Instruments and Derivative Instruments,to our Consolidated Financial Statements). Borrowings under the Senior Credit Facility have been used to finance our working capital needs and for general corporate purposes in the ordinary course of business, including the exploration, acquisition and development of oil and gas properties. Obligations under the Senior Credit Facility are secured by mortgages on the oil and gas properties of our subsidiaries located in the states of Illinois and Indiana. We are required to maintain liens covering our oil and gas properties representing at least 80% of our total value of all oil and gas properties.

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The Senior Credit Facility also requires we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total debt to EBITDAX. EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, such as our commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash activity. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, which includes the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day, known as our current ratio, must not be less than 1.0 to 1.0. Our current ratio as of December 31, 2011 was approximately 2.8 to 1.0. Additionally, the Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of EBITDAX for the period of four fiscal quarters ending on such day to interest expense for such period, known as our interest coverage ratio, must not be less than 3.0 to 1.0. Our interest coverage ratio as of December 31, 2011 was approximately 19.8 to 1.0. Additionally, as of the last day of any fiscal quarter, our ratio of total debt to EBITDAX for the period of four fiscal quarters ending on such day must not exceed 4.25 to 1.0. Our ratio of total debt to EBITDAX as of December 31, 2011 was approximately 2.9 to 1.0.

Second Lien Credit Agreement

On December 22, 2011, we entered into a second lien credit agreement (the “Second Lien Credit Agreement”) with KeyBank, as administrative agent, Wells Fargo Bank, N.A., as syndication agent, UnionBanCal Equities, Inc. and SunTrust Bank, as co-documentation agents, and the lenders from time to time party thereto. The Second Lien Credit Agreement provides for a $100.0 million senior secured second lien term loan facility under which $50.0 million is initially available to us and up to an additional $50.0 million of incremental borrowings may be available upon the request of the Company. The initial borrowings under the Second Lien Credit Agreement mature on March 28, 2016. The maturity of incremental borrowings will be determined at the time of such borrowings. In certain circumstances, we may be required to prepay borrowings under the Second Lien Credit Agreement. Management does not believe that a prepayment will be required within the next twelve months.

At our election, borrowings under the Second Lien Credit Agreement bear interest at a rate per annum equal to the “Alternate Base Rate” or “Adjusted LIBOR” (each as defined below), plus, in each case, an applicable per annum margin. The Alternative Base Rate is equal to the greater of: (i) KeyBank’s announced prime rate; (ii) the federal funds effective rate from time to time plus 0.5%; and (iii) the London Interbank Offered Rate for deposits with a maturity comparable to the borrowings (provided that such rate shall never be less than 1.0%) (“LIBOR Rate”) plus 1.0%. Adjusted LIBOR equals the product of the LIBOR Rate multiplied by a statutory reserve rate. The applicable per annum margin equals, in the case of loans bearing interest at the Alternate Base Rate, 5.0% through the first anniversary of the initial borrowings and 6.0% thereafter, and in the case of Adjusted LIBOR loans, 6.0% through the first anniversary of the initial borrowings and 7.0% thereafter. Interest is payable quarterly in the case of loans bearing interest at the Alternate Base Rate and on the last day of each relevant interest period or every three months in the case of loans bearing interest at the Adjusted LIBOR.

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The Second Lien Credit Agreement contains covenants that restrict our ability to, among other things, materially change our business, make dividends, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions. The Second Lien Credit Agreement states that as of the last day of any fiscal quarter, our current ratio must not be less than 1.0 to 1.0. Our current ratio as of December 31, 2011 was approximately 2.8 to 1.0. Additionally, the Second Lien Credit Agreement states that as of the last day of any fiscal quarter, our interest coverage ratio for the period of four fiscal quarters ending on such day must not to be less than 3.0 to 1.0. Our interest coverage ratio as of December 31, 2011 was approximately 19.8 to 1.0. Additionally, as of the last day of any fiscal quarter, our ratio of total debt to EBITDAX for the period of four fiscal quarters ending on such day is not to exceed 4.25 to 1.0. Our ratio of total debt to EBITDAX as of December 31, 2011 was approximately 2.9 to 1.0. Obligations under the Second Lien Credit Agreement are secured by mortgages on our oil and gas properties. We are required to maintain liens covering our oil and gas properties representing at least 80% of the total value of all of our oil and gas properties.

In connection with the Second Lien Agreement, we entered into a guaranty and second lien collateral agreement, dated as of December 22, 2011, in favor of KeyBank, as administrative agent for the banks and other financial institutions from time to time party to the Second Lien Credit Agreement (“the “Guaranty and Second Lien Collateral Agreement”). Pursuant to the Guaranty and Second Lien Collateral Agreement, we, jointly and severally, guaranteed the prompt and complete payment of our obligations under the Second Lien Credit Agreement. In addition, we granted, as security for the prompt and complete payment and performance when due of such obligations, a security interest in substantially all of our personal property, including equity interests.

As of December 31, 2011, we had $50.0 million drawn on the Second Lien Credit Agreement, for which we used the proceeds to finance the acquisition of certain oil and gas leases in Ohio and Pennsylvania, pay amounts outstanding under our the Senior Credit Facility, and for other general corporate purposes.

In addition to our Senior Credit Facility and Second Lien Credit Agreement, we may, from time to time in the normal course of business, finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and lines of credit consists of the following at December 31, 2011 and 2010:

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	December 31, 2011 (in thousands)			December 31, 2010 (in thousands)
Senior-Secured Lines of Credit(a)	$	225,000		$	10,000
Capital Leases and Other Obligations		544			949
Total Debts		225,544			10,949
Less Current Portion of Long-Term Debt(b)		(406	)		(829	)
Total Long-Term Debts	$	225,138		$	10,120

(a) The average interest rate on borrowings under our Senior Credit Facility for the year ended December 31, 2011 was approximately 2.5%. The average interest rate on borrowings under the Second Lien Credit Agreement for the year ended December 31, 2011 was approximately 8.3%. The average interest rate on our Other Loans and Notes Payable is approximately 2.3%. The average interest rate on borrowings under our Senior Credit Facility for the year ended December 31, 2010 was approximately 2.3%. The average interest rate on our Other Loans and Notes Payable is approximately 2.4%.

(b) Classified as Accounts Payable on our Consolidated Balance Sheets.

The following is the principal maturity schedule for debt outstanding as of December 31, 2011:

	Year Ended December 31, (in thousands)
2012	$	406
2013		138
2014		0
2015		175,000
2016		50,000
Thereafter		0
Total	$	225,544

12. FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVE INSTRUMENTS

Our results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we enter into oil and natural gas commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of December 31, 2011, 2010 and 2009, our oil and natural gas derivative commodity instruments consisted of fixed rate swap contracts, puts, collars, swaptions and put spreads. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain (Loss) on Derivatives, Net. For additional information, see Note 2,Summary of Significant Accounting Policies, to our Consolidated Financial Statements.

Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our

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payment of a cash premium. If the put strike price is greater than the market price for a settlement period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a settlement period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. Swaption agreements provide options to counterparties to extend swaps into subsequent years.

We enter into the majority of our derivative arrangements with four counterparties and have a netting agreement in place with these counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 8, Concentrations of Credit Risk, to our Consolidated Financial Statements.

None of our derivatives are designated for hedge accounting but are, to a degree, an economic offset to our oil and natural gas price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all unrealized and realized gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Income (Expense).

We received net cash receipts from continuing operations of $6.2 million, $0.1 million and $9.6 million for the years ended December 31, 2011, 2010 and 2009, respectively. During the first quarter of 2009, we redeemed our oil hedges related to production in 2011 for net cash proceeds of approximately $4.6 million. Unrealized gains and losses from continuing operations associated with our derivative instruments amounted to a gain of $12.7 million and $6.0 million and a loss of $17.6 million for the years ended December 31, 2011, 2010 and 2009, respectively.

The following table summarizes the location and amounts of gains and losses on derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009:

	Year Ended December 31, 2011 (in thousands)
	Realized Gains (Losses)		Unrealized Gains (Losses)		Total
Crude Oil
Reclassification of settled contracts included in prior periods mark-to-market adjustments	$	0	$	1,850	$	1,850

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Mark-to-market fair value adjustments		0			(1,488	)		(1,488	)
Settlement of contracts(a)		(670	)		0			(670	)
Crude Oil Total		(670	)		362			(308	)
Natural Gas
Reclassification of settled contracts included in prior periods mark-to-market adjustments		0			(4,231	)		(4,231	)
Mark-to-market fair value adjustments		0			16,573			16,573
Settlement of contracts(a)		6,882			0			6,882
Natural Gas Total		6,882			12,342			19,224
Gain (Loss) on Derivatives, Net	$	6,212		$	12,704		$	18,916

(a) These amounts represent the realized gains and losses on settled derivatives, which before settlement are included in the mark-to-market fair value adjustments.

	Year Ended December 31, 2010 (in thousands)
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total
Crude Oil
Reclassification of settled contracts included in prior periods mark-to-market adjustments	$	0		$	5,782		$	5,782
Mark-to-market fair value adjustments		0			(2,819	)		(2,819	)
Settlement of contracts(a)		(3,861	)		0			(3,861	)
Crude Oil Total		(3,861	)		2,963			(898	)
Natural Gas
Reclassification of settled contracts included in prior periods mark-to-market adjustments		0			(1,925	)		(1,925	)
Mark-to-market fair value adjustments		0			4,211			4,211
Settlement of contracts(a)		4,667			0			4,667
Natural Gas Total		4,667			2,286			6,953
Interest Rate
Reclassification of settled contracts included in prior periods mark-to-market adjustments		0			711			711

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Mark-to-market fair value adjustments		0			0		0
Settlement of contracts(a)		(711	)		0		(711	)
Interest Rate Total		(711	)		711		0
Gain (Loss) on Derivatives, Net	$	95		$	5,960	$	6,055

(a) These amounts represent the realized gains and losses on settled derivatives, which before settlement are included in the mark-to-market fair value adjustments.

	Year Ended December 31, 2009 (in thousands)
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total
Crude Oil
Reclassification of settled contracts included in prior periods mark-to-market adjustments	$	0		$	(10,331	)	$	(10,331	)
Mark-to-market fair value adjustments		0			(8,114	)		(8,114	)
Settlement of contracts(a)		7,198			0			7,198
Crude Oil Total		7,198			(18,445	)		(11,247	)
Natural Gas
Reclassification of settled contracts included in prior periods mark-to-market adjustments		0			(1,091	)		(1,091	)
Mark-to-market fair value adjustments		0			1,518			1,518
Settlement of contracts(a)		3,216			0			3,216
Natural Gas Total		3,216			427			3,643
Interest Rate
Reclassification of settled contracts included in prior periods mark-to-market adjustments		0			611			611
Mark-to-market fair value adjustments		0			(151	)		(151	)
Settlement of contracts(a)		(769	)		0			(769	)
Interest Rate Total		(769	)		460			(309	)
Gain (Loss) on Derivatives, Net	$	9,645		$	(17,558	)	$	(7,913	)

(a) These amounts represent the realized gains and losses on settled derivatives, which before settlement are included in the mark-to-market fair value adjustments.

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Our derivative instruments are recorded on the balance sheet as either an asset, or a liability, measured at its fair value. The fair value associated with our derivative instruments was an asset of approximately $15.3 million and $2.6 million at December 31, 2011 and 2010, respectively. The fair value is based on the valuation methodologies of our counterparties and third-party valuation providers. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2011 consisted of:

Period	Volume		Put Option		Floor		Ceiling		Swap		Fair Market Value ($ in Thousands)
Oil
2012 – Collar		660,000 Bbls	$	0	$	69.44	$	110.21	$	0	$	(2,363	)
2013 – Collar		300,000 Bbls		0		72.40		116.30		0		(490	)
		960,000 Bbls									$	(2,853	)
Natural Gas
2012 – Swap		2,400,000 Mcf	$	0	$	0	$	0	$	5.04	$	3,912
2012 – Swaption		600,000 Mcf		0		0		0		5.25		1,047
2012 – Collar		3,000,000 Mcf		0		4.70		5.89		0		4,112
2012 – 3-Way Collar		2,640,000 Mcf		3.66		4.48		5.13		0		1,333
2013 – Put		2,640,000 Mcf		0		5.00		0		0		2,730
2013 – Swap		2,880,000 Mcf		0		0		0		4.30		1,377
2013 – Collar		3,360,000 Mcf		0		4.77		5.68		0		3,465
2013 – 3-Way Collar		1,920,000 Mcf		3.53		4.38		5.08		0		861
2014 – Call		1,800,000 Mcf		0		0		5.00		0		(642	)
		21,240,000 Mcf									$	18,195

The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of December 31, 2011 and December 31, 2010 is summarized below.

	December 31, 2011 (in  thousands)	December 31, 2010 (in  thousands)
Short-Term Derivative Assets:

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Natural Gas – Swaption	$	1,047		$	0
Natural Gas – Swaps		3,912			519
Natural Gas – Collars		4,112			1,132
Natural Gas – 3-Way Collars		1,333			0
Natural Gas – Puts		0			2,464
Natural Gas – Put Spread		0			449
Total Short-Term Derivative Assets	$	10,404		$	4,564
Long-Term Derivative Assets:
Crude Oil – Collars	$	143		$	63
Natural Gas – Swaps		1,377			663
Natural Gas – 3-Way Collars		861			0
Natural Gas – Put		505			0
Natural Gas – Collars		5,690			723
Total Long-Term Derivative Assets	$	8,576		$	1,449
Total Derivative Assets	$	18,980		$	6,013
Short-Term Derivative Liabilities:
Crude Oil – Collars	$	(2,363	)	$	(1,850	)
Natural Gas – Collars		0			(10	)
Total Short-Term Derivative Liabilities	$	(2,363	)	$	(1,860	)
Long-Term Derivative Liabilities:
Crude Oil – Collars	$	(632	)	$	(1,428	)
Natural Gas – Call		(643	)		0
Natural Gas – Collars		0			(88	)
Total Long-Term Derivative Liabilities	$	(1,275	)	$	(1,516	)
Total Derivative Liabilities	$	(3,638	)	$	(3,376	)

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We

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utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Level 2—Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table presents the fair value hierarchy table for assets and liabilities measured at fair value ($ in thousands):

	Fair Value Measurements at December 31, 2011 Using:
	Total Carrying Value as of December 31, 2011			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivatives(a) – commodity swaps, collars and put options	$	15,342		$	0	$	15,342	$	0
Asset Retirement Obligations	$	(18,670	)	$	0	$	0	$	(18,670	)

(a) All of our derivatives are classified as Level 2 measurements. For information regarding their classification on our Consolidated Balance Sheets, please refer to the table on page F-46 of this report.

Our derivative contracts are valued by third parties using valuation models that are primarily industry-standard models that consider various inputs including: quoted forward prices; time value; volatility factors; and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify

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those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative commodity swaps and collars and interest rate swaps are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments.

Asset Retirement Obligations

We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances which represent the entirety of our Level 3 fair value measurements.

13. INCOME TAXES

We recognize deferred tax liabilities and assets for the expected future tax consequences of events that may be recognized in our financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial carrying amounts and tax bases of assets and liabilities using enacted tax rates. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

All information in the tables below includes results from continuing operations and discontinued operations.

	Year Ended December 31, 2011 (in thousands)			Year Ended December 31, 2010 (in thousands)		Year Ended December 31, 2009 (in thousands)
Current:
Federal	$	63		$	11	$	0
State		244			292		0
Deferred:
Federal		(6,778	)		3,316		(9,626	)
State		(561	)		456		(1,088	)
Total Income Tax Expense (Benefit)	$	(7,032	)	$	4,075	$	(10,714	)

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A reconciliation of income tax expense (benefit) using the statutory U.S. income tax rate compared with actual income tax expense is as follows:

	Year Ended December 31, 2011 (in thousands)			Year Ended December 31, 2010 (in thousands)			Year Ended December 31, 2010 (in thousands)
Net income (loss) before noncontrolling interests and income taxes	$	(22,402	)	$	10,111		$	(26,947	)
Statutory U.S. income tax rate		35.0	%		35.0	%		35.0	%
Tax expense (benefit) recognized using statutory U.S. income tax rate	$	(7,841	)	$	3,539		$	(9,431	)
Change in estimated future state rate		612			77			301
Permanent differences		176			33			7
Valuation Allowance		1,031			0			0
Other		110			(167	)		(230	)
Adjusted federal income tax expense (benefit)	$	(5,912	)	$	3,482		$	(9,353	)
State income tax expense (benefit)		(1,120	)		593			(1,361	)
Total income tax expense (benefit)	$	(7,032	)	$	4,075		$	(10,714	)
Effective income tax rate		31.4	%		40.3	%		39.8	%

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax liabilities (assets) are comprised of the following at December 31, 2011 and 2010.

	December  31, 2011 (in thousands)			December 31, 2010 (in  thousands)
Tax effects of temporary differences for:
Current:
Assets:
G&G amortization	$	1,020		$	1,056
Valuation allowance		(175	)		0
Other		329			6
Total current deferred tax assets		1,174			1,062
Liabilities:
Unrealized gain on derivatives		(3,315	)		(1,100	)
Deferred gain on early hedge settlements		0			(1,870	)

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Total current deferred tax liabilities		(3,315	)		(2,970	)
Net total current deferred tax liability		(2,141	)		(1,908	)
Long-Term:
Assets:
Asset retirement obligation		7,704			7,030
Valuation allowance		(1,688	)		0
Non-Cash compensation plans		2,095			1,780
Net operating loss carryforward		15,714			6,550
Organization costs		763			827
Other		375			503
Total long-term deferred tax assets		24,963			16,690
Liabilities:
Unrealized gain on derivatives		(3,010	)		0
Timing differences – tax partnerships		(1,818	)		0
Book basis of oil and gas properties in excess of tax basis		(18,434	)		(22,430	)
Other		(58	)		(190	)
Total long-term deferred tax liabilities		(23,320	)		(22,620	)
Net total long-term deferred tax asset (liability)	$	1,643		$	(5,930	)

Management continuously evaluates the facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. These deferred tax assets consist primarily of net operating losses and deductible temporary differences. For the year ended December 31, 2011, management determined, based on positive and negative evidence examined and anticipated future taxable income, that it was appropriate to assign a valuation allowance for statutory depletion carryforwards and charitable contributions of approximately $1.9 million. We have established a full valuation allowance against unused charitable contribution deductions, which in the absence of sufficient future taxable income, are likely to expire unused. Based on the expected patterns of reversal of all existing temporary differences, we have concluded that it is more likely than not that the remaining deferred tax assets will be realized. Prior to 2011, we have not required any valuation allowances.

Our management will continue, in future periods, to assess the likely realization of the deferred tax assets. The valuation allowance may change based on future changes in circumstances.

At December 31, 2011, we had available unused net operating loss carryforwards that may be applied against future taxable income that expire as follows:

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Year of Expiration	Net Operating Loss Carryforwards (in thousands)
2027	$	27
2028		11,392
2029		2,160
2030		153
2031		25,781
Total	$	39,513
Statutory Rate		39.77	%
Tax Effected NOL	$	15,714

FASB ASC 740-10 sets forth a two-step process for evaluating tax positions. The first step is financial statement recognition of the tax position based on whether it is more likely than not that the position will be sustained upon examination by taxing authorities and resolution through related appeals or litigation, based on the technical merits of the case. FASB ASC 740-10 mandates certain assumptions in applying the more likely than not judgment, including the presupposition of an examination where the taxing authorities are fully informed of all relevant information for evaluation of the tax position. In other words, FASB ASC 740-10 precludes factoring the likelihood of a tax examination into the evaluation of the outcome so that the evaluation is to focus solely on the technical merits of the position.

Our management has concluded that, as of December 31, 2011, we have not taken any tax positions that would require disclosure as “unrecognized positions” and that no liability balance is required to offset any unsustainable positions. We did not have any accrued interest or penalties as of December 31, 2011 and 2010.

We file a consolidated federal income tax return and separate or consolidated state income tax returns in the United States Federal jurisdiction and in many state jurisdictions. We are subject to U.S. Federal income tax examinations and to various state tax examinations for periods after August 1, 2007.

14. EARNINGS PER COMMON SHARE

Basic income per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market based, given that the hypothetical effect is not anti-dilutive. For the year ending December 31, 2011, we excluded 603,064 stock options from the computation of diluted earnings per share because their effect would have

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been anti-dilutive. Stock options of 715,106 for the year ending December 31, 2010 were outstanding but not included in the computations of diluted net income per share because their effect would be anti-dilutive. Due to our net loss for the year ended December 31, 2009, we excluded all 873,837 of outstanding stock options because the effect would have been anti-dilutive to the computations (for additional information on our stock options and SARs, see Note 17, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share data):

	Year Ended December 31, 2011			Year Ended December 31, 2010			Year Ended December 31, 2009
Numerator (in thousands):
Net Income (Loss) From Continuing Operations	$	18,088		$	8,058		$	(16,556	)
Net Income (Loss) From Discontinued Operations		(33,457	)		(2,022	)		323
Net Income (Loss)	$	(15,369	)	$	6,036		$	(16,233	)
Denominator (in thousands):
Weighted Average Common Shares Outstanding – Basic		43,930			43,281			36,806
Effect of Dilutive Securities:
Employee Stock Options		95			112			0
Employee Performance-Based Restricted Stock Awards		451			277			0
Weighted Average Common Shares Outstanding – Diluted		44,476			43,670			36,806
Earnings per Common Share (a):
Basic —Net Income (Loss) From Continuing Operations	$	0.41		$	0.18		$	(0.45	)
—Net Income (Loss) From Discontinued Operations		(0.76	)		(0.05	)		0.01
—Net Income (Loss)	$	(0.35	)	$	0.13		$	(0.44	)
Diluted —Net Income (Loss) From Continuing Operations	$	0.41		$	0.18		$	(0.45	)
—Net Income (Loss) From Discontinued Operations		(0.76	)		(0.05	)		0.01
—Net Income (Loss)	$	(0.35	)	$	0.13		$	(0.44	)

(a) All earnings per share amounts are attributable to Rex common shareholders

15. CAPITAL STOCK

Currently, our common stock is traded on the NASDAQ Global Market under the trading symbol “REXX”. We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. In January 2010, we completed a public offering of 6,900,000 shares of common stock

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at an offering price of $12.25 per share. The net proceeds from the offering were approximately $80.2 million, after deducting underwriting discounts, commissions and estimated offering expenses. We used a portion of the proceeds to repay outstanding borrowings under our Senior Credit Facility and used the remaining net proceeds to fund a portion of our capital expenditure program for 2010 and for other general corporate purposes. As of December 31, 2011 and 2010, we had 44,859,220 and 44,306,677 shares of common stock outstanding, respectively. For additional information see Note 26, Subsequent Events, to our Consolidated Financial Statements.

16. MAJOR CUSTOMERS

Approximately 91.6% of our oil and natural gas sales from continuing operations for the three-year period ended December 31, 2011, have been sold to five customers, with the production mix becoming more diversified each subsequent year. In 2009, approximately $42.9 million, or 88.4%, of our commodity sales from continuing operations were to three customers, with $41.4 million, or 85.3%, coming from a single customer. In 2010, approximately $62.0 million, or 92.2%, of our commodity sales from continuing operations were derived from five customers, with the largest customer being responsible for approximately $51.9 million, or 77.2%, of total commodity sales. For the year ended December 31, 2011, approximately $103.6 million, or 92.6%, of our commodity sales from continuing operations were attributable to four customers with the largest single purchaser accounting for $62.9 million, or 56.2%.

17. EMPLOYEE BENEFIT AND EQUITY PLANS

401(k) Plan

We sponsor a 401(k) Plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan are discretionary. Our contributions to the plan attributable to continuing operations were approximately $0.4 million, $0.3 million and $0.1 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Equity Plans

We recognize all share-based payments to employees, including grants of employee stock options, in the income statement based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period. We report any benefits of tax deductions in excess of recognized compensation as a financing cash flow, rather than as an operating cash flow.

2007 Long-Term Incentive Plan

We have granted stock options, stock appreciation rights and restricted stock awards to various employees and non-employee directors under the terms of our 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the Compensation Committee of our board of directors (the

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“Compensation Committee”). Among the Compensation Committee’s responsibilities are selecting participants to receive awards, determining the form, amount and other terms and conditions of awards, interpreting the provisions of the Plan or any award agreement and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees, are intended to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes. The Compensation Committee has authorized the issuance of 3,079,470 shares under the Plan, with 929,635 and 1,408,494 still available as of December 31, 2011 and 2010, respectively.

All awards granted under the Plan have been issued at the prevailing market price at the time of the grant. All outstanding stock options have been awarded with five or ten year expiration at an exercise price equal to our closing price on the NASDAQ Global Market on the day of the award. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively.

Stock Options

During the year ended December 31, 2011, the Compensation Committee awarded nonqualified options to purchase a total of 90,074 shares of our common stock to three employees. During the year ended December 31, 2010, the Compensation Committee awarded nonqualified options to purchase a total of 111,174 shares of our common stock to three employees and five non-employee directors. The nonqualified stock options granted to our employees and non-employee directors during 2010 and 2011 have an exercise price equal to the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable in one-third increments on the first, second or third anniversary of the grant date, provided that the option holder remains our employee or a director until that date. All options also provide that all unvested options vest and become immediately exercisable upon a “change in control” of us; as such term is defined in the Plan.

During fiscal year 2009, with the approval of our Compensation Committee, we modified the terms of certain stock option award agreements of three former employees located in our Southwest Region to partially vest options previously granted to such individuals. The options were partially vested pursuant to the terms of severance agreements entered into with the former employees as a result of the termination of their employment following the sale of our Southwest Region assets and the closing of our Midland, Texas office in March 2009. As modified, the options partially vested and became exercisable with respect to a total of 58,749 shares of our common stock which had an exercise price of $9.99. We recognized approximately $0.3 million in compensation expense related to these awards, $0.2 million of which would have been recognized over the remaining life of the options had they not been accelerated.

Stock options represent the right to purchase shares of stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or

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otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, shall again be available for the purposes of the Plan. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the Plan or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the Plan.

A summary of the stock option activity is as follows:

	Number of Shares			Weighted Average Exercise Price		Weighted Average Remaining Term (in years)		Aggregate Intrinsic Value (in thousands)
Options outstanding, December 31, 2008		993,700		$	13.81
Granted		68,888			4.84
Exercised		0			0
Cancelled/Forfeited		(188,751	)		12.06
Options outstanding, December 31, 2009		873,837		$	13.41
Granted		111,174			11.83
Exercised		(22,000	)		9.99
Cancelled/Forfeited		(136,500	)		18.18
Options outstanding, December 31, 2010		826,511		$	12.50
Granted		90,074			12.74
Exercised		(139,682	)		9.75
Cancelled/Forfeited		(78,576	)		13.75
Options Outstanding, December 31, 2011		698,327		$	12.94		4.7	$	2,470
Options Exercisable, December 31, 2011		566,385		$	13.26		4.8	$	2,052

Stock-based compensation expense from continuing operations relating to stock options for the years ended December 31, 2011, 2010 and 2009 totaled $0.7 million, $1.0 million and $1.0 million, respectively. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative expense. The intrinsic value of stock options exercised for the years ended December 31, 2011, 2010 and 2009 was $0.3 million, $49,000 and $0, respectively. The total tax benefit for the years ended December 31, 2011, 2010 and 2009 was $0.1 million, $19,000 and $0, respectively.

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The fair value of each option grant is estimated on the date of the grant using the Black-Scholes option-pricing model with the following assumptions:

	Year Ended December 31,
	2011			2010			2009
Expected dividend yield		0	%		0	%		0	%
Expected stock price volatility		74.7	%		90	%		72	%
Risk-free interest rate		0.63	%		1.66	%		1.87	%
Expected life of options (years)		4			4-6.5			4-6.5

The dividend yield of zero is based on the fact that we have never paid cash dividends on common stock and have no present intention of doing so. Our expected historical volatility factor was determined by assessing the common stock trading history of eight publicly-traded oil and gas companies that we determined to be similar to us in ways such as their operating strategy, capital structure, production mix and volume and asset size in addition to our own historical volatility. The risk-free interest rate was determined by interpolating the average yield on a U.S. Treasury bond for a period approximately equal to the expected average life of the options. The average expected life has been determined using the “simplified method” in which the average expected life of the option is equal to the average of the term of the option and the vesting period. We elected to use the simplified method for determining the average expected life because we do not have a history on which to base estimates for the term to exercise of our granted stock options. We used an estimated forfeiture rate of 26.0% in 2011 for calculating stock-based compensation expense related to stock options and this rate is based on historical experience.

Based on the above assumptions, the weighted average estimated fair value of options granted during the years ended December 31, 2011, 2010 and 2009 was $6.06 per share, $6.74 per share and $3.26 per share, respectively. The weighted average exercise price of options granted during 2011, 2010 and 2009 was $12.78, $11.83 and $4.84 per share, respectively.

A summary of the status of our issued and outstanding stock options as of December 31, 2011 is as follows:

		Outstanding						Exercisable
Exercise Price		Number Outstanding at 12/31/11		Weighted- Average Remaining Contractual Life (Years)		Weighted- Average Exercise Price		Number Exercisable at 12/31/11		Weighted- Average Exercise Price
$	9.99		230,499		5.9	$	9.99		230,499	$	9.99
$	9.50		100,000		5.9	$	9.50		100,000	$	9.50
$	13.56		12,500		6.1	$	13.56		12,500	$	13.56
$	22.34		30,000		6.3	$	22.34		30,000	$	22.34

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$	23.88	75,000	1.4	$	23.88	75,000	$	23.88
$	23.28	4,000	1.5	$	23.28	4,000	$	23.28
$	19.92	13,000	1.6	$	19.92	13,000	$	19.92
$	21.10	30,000	1.7	$	21.10	30,000	$	21.10
$	5.04	46,041	7.4	$	5.04	30,696	$	5.04
$	10.42	29,548	8.5	$	10.42	9,848	$	10.42
$	13.01	18,526	3.8	$	13.01	6,175	$	13.01
$	12.50	19,139	3.9	$	12.50	6,380	$	12.50
$	11.87	3,500	4.3	$	11.87	0	$	0
$	12.30	36,574	1.1	$	12.30	18,287	$	12.30
$	13.19	50,000	4.8	$	13.19	0	$	0
	Total	698,327	4.7		12.94	566,385		13.26

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at December 31, 2011 were 4.7 years and $2.5 million, respectively. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at December 31, 2010 were 6.7 years and $2.5 million, respectively. As of December 31, 2011, unrecognized compensation expense related to stock options totaled approximately $0.5 million, which will be recognized over a weighted average period of 2.4 years.

Stock Appreciation Rights

During the year ended December 31, 2008, the Compensation Committee awarded 109,500 stock appreciation rights (“SARs”) to five employees, and there were no awards made in 2009, 2010 or 2011. SARs represent the right to receive cash or shares of common stock in the future equivalent to the difference between the fair market value at the time of exercise and the strike price. The SARs have an exercise price equal to $13.56, the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable on the third anniversary of the grant date, provided that the holder remains our employee until that date. The SARs also provide that all unvested SARs vest and become immediately exercisable upon a “change in control” of us, as such term is defined in the Plan. The outstanding SARs issued as of December 31, 2011 may only be exercised for cash settlement. We incurred expense related to these awards of $0, a credit of $0.2 million and expense of $0.3 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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	Outstanding											Exercisable
Strike Price	Number of SARs Granted		SARs Forfeited or Cancelled			SARs Outstanding		Weighted- Average Remaining Contractual Life (Years)		Weighted- Average Strike Price		SARs		Weighted- Average Exercise Price
$      13.56		109,500		(89,000	)		20,500		6.1	$	13.56		0	$	0
Total		109,500		(89,000	)		20,500		6.1	$	13.56		0	$	0

As of December 31, 2011, the aggregate intrinsic value of SARs outstanding was approximately $25,000. There have been no SAR exercises to date. All of our SARs were granted in 2008 with grant date fair values of $6.91 per share based on a weighted average exercise price of $13.56 per share, expected annual dividends per share of 0.0%, expected life in years of 6.5, expected volatility of 45.1% and a risk-free interest rate of 4.1%. The dividend yield of zero is based on the fact that we have never paid cash dividends on common stock and have no present intention of doing so. Our expected historical volatility factor was determined by assessing the common stock trading history of eight publicly-traded oil and gas companies that we determined to be similar to us in ways such as their operating strategy, capital structure, production mix and volume and asset size. The risk-free interest rate was determined by interpolating the average yield on a U.S. Treasury bond for a period approximately equal to the expected average life of the SARs. The average expected life has been determined using the “simplified method” in which the average expected life of the SARs is equal to the average of the term of the SARs and the vesting period. We elected to use the simplified method for determining the average expected life because we do not have a history on which to base estimates for the term to exercise of our granted stock options. We do not use an estimated forfeiture rate as all awards are expected to vest and become exercisable.

Restricted Stock Awards

During the year ended December 31, 2011, the Compensation Committee issued 709,890 shares of restricted common stock to selected employees and non-employee directors. During the year ended December 31, 2010, the Compensation Committee issued 860,563 shares of restricted common stock to selected employees and non-employee directors. The shares granted in 2011 and 2010 are subject to time vesting and performance-based vesting. The shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date through the third anniversary of the grant date. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. The restricted common stock is valued at the closing price of our common stock on the NASDAQ Global Market on the date of the grant. Upon a “change in control” of us, as such term is defined in the Plan, all restrictions will immediately lapse for performance-based awards to varying degrees based on performance metrics at the time of the change in control. For awards that do not contain a performance-based condition, all restrictions immediately lapse upon a change in control. Compensation expense associated with the restricted stock award is recognized on a straight-line basis over the vesting period.

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We recorded compensation expense related to restricted common stock awards of $0.9 million, $0.1 million and $0.2 million for the years ended December 31, 2011, 2010 and 2009, respectively. As of December 31, 2011, total unrecognized compensation cost related to the restricted common stock grants was approximately $3.3 million to be recognized over a weighted average of 2.5 years.

A summary of the restricted stock activity for the years ended December 31, 2011, 2010 and 2009 is as follows:

	Number of Shares			Weighted- Average Grant Date Fair Value
Restricted stock awards, as of January 1, 2009		20,000		$	23.00
Awards		261,850			2.05
Forfeitures		(33,750	)		2.05
Restricted stock awards, as of December 31, 2009		248,100		$	3.74
Awards		860,563			12.07
Forfeitures		(293,698	)		7.99
Restricted stock awards, as of December 31, 2010		814,965		$	11.01
Awards		755,816			13.07
Forfeitures		(342,955	)		11.60
Restricted stock awards, as of December 31, 2011		1,227,826		$	12.11

18. IMPAIRMENT EXPENSE

For the years ended December 31, 2011, 2010 and 2009, we incurred impairment expense from continuing operations of approximately $14.6 million, $8.9 million and $1.6 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment (for additional information see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements). During 2011, we incurred approximately $11.6 million of expense related to the impairment of proved conventional shallow natural gas wells in the Appalachian Basin. In addition to the impairment related to our conventional shallow natural gas properties, we incurred approximately $1.4 million in impairment expense related to the expiration or surrender of undeveloped acreage and $1.6 million in impairment expense related to a refrigeration plant in the Appalachian Basin which was formerly in use before the commencement of operations at our cryogenic gas processing plant in Butler County, Pennsylvania. With larger scale gas processing capabilities in the region there is no further value for the refrigeration plant. During 2010, we determined that the carrying values of two of our test wells in Clearfield County, Pennsylvania, which were in various stages of drilling and completion, and did not hold proved reserves, were not recoverable due to a lack of a sales outlet and no current plans by us to complete the wells for

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commercial production. The carrying value of these wells before impairment was approximately $3.9 million. In addition, we incurred approximately $2.3 million in impairment expense related to the expiration or surrender of undeveloped acreage. The impairment expense incurred during 2009 was primarily due to the expiration and surrender of undeveloped acreage.

19. SUSPENDED EXPLORATORY WELL COSTS

We capitalize the costs of exploratory wells if a well finds a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

The following table reflects the net change in capitalized exploratory well costs, excluding those related to Assets Held for Sale on our Consolidated Balance Sheets for the years ended December 31, 2011, 2010 and 2009 ($ in thousands):

	2011			2010			2009
Beginning Balance at January 1,	$	1,637		$	5,107		$	2,213
Additions to capitalized exploratory well costs pending the determination of estimated proved reserves		106,045			34,330			2,894
Divested wells		0			(10,770	)		0
Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves		(95,926	)		(23,016	)		0
Capitalized exploratory well costs charged to expense		0			(4,014	)		0
Ending Balance at December 31,		11,756			1,637			5,107
Less exploratory well costs that have been capitalized for a period of one year or less		(11,756	)		(1,637	)		(2,894	)
Capitalized exploratory well costs for a period of greater than one year	$	0		$	0		$	2,213
Number of projects that have exploratory well costs capitalized for a period of more than one year		0			0			2

As of December 31, 2009 we had approximately $2.2 million in capitalized exploratory well costs that were capitalized for a period greater than one year. These costs related to two wells in our Appalachian Basin. These wells are in various stages of drilling and completion. On January 1, 2010, Williams became the operator of this joint venture area and does not currently have any plans to complete these wells and connect them into a sales line. While we still believe that these wells are capable of producing commercial quantities of natural gas, the lack of a sales line and plans to construct one give rise to substantial doubt about the carrying values of these wells. We subsequently expensed the carrying values of these wells in 2010, which is classified as Impairment Expense on our Consolidated Statement of Operations.

20. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (UNAUDITED)

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Costs incurred in oil and natural gas property acquisitions and development are presented below and exclude any costs incurred related to Assets Held for Sale (in thousands):

	2011		2010		2009
Consolidated Entities:
Acquisition of Properties
Proved	$	9	$	53	$	39
Unproved		76,852		43,166		17,949
Exploration Costs		113,075		36,008		12,852
Development Costs (a)		61,920		24,825		12,211
Subtotal		251,856		104,052		43,051
Asset Retirement Obligations		316		186		255
Total Costs Incurred	$	252,172	$	104,238	$	43,306
Share of Equity Method Investments:
Acquisition of Properties
Proved	$	0	$	0	$	0
Unproved		0		0		0
Exploration Costs		0		0		0
Development Costs (a)		12,682		6,018		1,241
Total	$	12,682	$	6,018	$	1,241

(a) Includes Depreciation expense for support equipment and facilities.

21. OIL AND NATURAL GAS CAPITALIZED COSTS (UNAUDITED)

Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below and exclude any properties classified as Assets Held for Sale (in thousands):

	2011		2010
Consolidated Entities:
Proven Oil and Natural Gas Properties	$	349,938	$	223,558
Pipelines and Support Equipment		30,926		31,610

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Field Operation Vehicles and Other Equipment		9,489			7,471
Wells and Facilities in Progress		61,355			34,735
Unproven Properties		123,241			64,115
Total		574,949			361,489
Less Accumulated Depreciation and Depletion		(104,894	)		(91,134	)
Total	$	470,055		$	270,355
Share of Equity Method Investments:
Pipelines and Support Equipment	$	25,344		$	10,841
Field Operation Vehicles and Other Equipment		36			29
Wells and Facilities in Progress		16,637			4,122
Total		42,017			14,992
Less Accumulated Depreciation and Depletion		(1,817	)		(180	)
Total	$	40,200		$	14,812

22. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED)

Our independent engineers, Netherland, Sewell, and Associates, Inc. (“NSAI”) evaluated all of our proved oil and natural gas reserves for the years ended December 31, 2011, 2010 and 2009. The technical persons responsible for preparing the estimates of our estimated proved reserves meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. We emphasize that reserve estimates are inherently imprecise. Our oil and natural gas reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available. All of our estimated proved reserves are located within the United States.

Proved oil and natural gas reserves represent the estimated quantities of oil and natural gas which geoscience and engineering data demonstrate with reasonable certainty will be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and governmental regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed oil and natural gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes

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expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Estimated proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated unless such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. See Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements. We adopted the rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, are included in our reserves estimates.

Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2011, 2010 and 2009.

	2011
	Oil and NGLs (Bbls)			Natural Gas (Mcf)			Mcf Equivalents
Estimated Proved Reserves – Beginning of Period		12,342,828			127,621,835			201,678,803
Extensions and Discoveries		2,796,834			139,067,694			155,848,698
Revisions of Previous Estimates		1,060,941			16,515,036			22,880,682
Production(a)		(884,602	)		(8,912,250	)		(14,219,862	)
Estimated Proved Reserves – End of Period		15,316,001			274,292,315			366,188,321
	2010
	Oil and NGLs (Bbls)			Natural Gas (Mcf)			Mcf Equivalents
Estimated Proved Reserves – Beginning of Period		11,509,983			56,163,170			125,223,068
Sale of Reserves in Place		(369,758	)		(12,251,612	)		(14,470,160	)
Extensions and Discoveries		3,461,768			93,229,532			114,000,140
Revisions of Previous Estimates		(1,542,033	)		(6,511,733	)		(15,763,931	)
Production(a)		(717,132	)		(3,007,522	)		(7,310,314	)
Estimated Proved Reserves – End of Period		12,342,828			127,621,835			201,678,803

(a) Gas production excludes certain production associated with gas sales contracts for which we do not recognize reserves. See Note 9,Commitments and Contingencies, to our Consolidated Financial Statements.

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	2009
	Oil and NGLs (Bbls)			Natural Gas (Mcf)			Mcf Equivalents
Estimated Proved Reserves – Beginning of Period		5,993,626			30,019,477			65,981,233
Purchases of Reserves in Place		—			—			—
Extensions and Discoveries		940,883			18,422,999			24,068,297
Revisions of Previous Estimates		5,302,862			9,231,194			41,048,366
Production (a)		(727,388	)		(1,510,500	)		(5,874,828	)
Estimated Proved Reserves – End of Period		11,509,983			56,163,170			125,223,068

(a) Oil production does not include approximately 372 barrels of oil produced attributable to a small oil field that was sold during 2009 and was not evaluated for purposes of reserves in 2008.

	Oil and NGLs (Bbls)		Natural Gas (Mcf)		Mcf Equivalent
Proved Developed Reserves
December 31, 2011		10,399,620		110,853,300		173,251,020
December 31, 2010		8,799,105		32,477,226		85,271,856
December 31, 2009		8,623,430		16,161,494		67,902,074

Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from developmental drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs.

We had significant revisions in our oil, NGL and natural gas reserves for the year ended December 31, 2011. The majority of our positive revision of estimated proved reserves occurred in our Marcellus Shale properties, where our average per well estimated ultimate recovery (“EUR”) increased from 4.4 Bcfe to 5.3 Bcfe in our operated areas and from 3.0 Bcf to 4.2 Bcf in our non-operated areas. In total, our positive revisions in our Marcellus operations accounted for 84% of all revisions. Also impacting our revisions during 2011 was a change in the oil pricing from $76.03 per barrel in 2010 to $92.45 per barrel in 2011. We had significant revisions in our oil and NGL reserves of approximately 1.5 MMBOE for the year ended December 31, 2010, which were primarily due to a decrease in the pricing

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used for our NGLs from $57.65 per barrel in 2009 to $31.71 per barrel in 2010. The increase in our oil and NGL reserves of 5.3 MMBOE as of December 31, 2009 through revisions was primarily due to an increase in the price of oil used in the reserves estimates from $41.00 per barrel in 2008 to $57.65 per barrel in 2009. The increase in our natural gas reserves of 9.2 Bcfe as of December 31, 2009 through revisions was primarily due to a positive development and production history, which was partially offset by a decrease in the natural gas price used from $5.71 in 2008 to $3.87 in 2009.

Extensions, discoveries and other additions. These are additions to estimated proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with estimated proved reserves or of new reservoirs of estimated proved reserves in old fields.

We had significant extensions, discoveries and other additions for the year ended December 31, 2011, of 2.8 MMBOE of oil and NGLs and 139.1 Bcf of natural gas. These additions were primarily due to the additional proved undeveloped locations that were added to our proved reserve estimates that were a result of our continued drilling success in the Marcellus Shale. A portion of the extension and discoveries were booked as a result of successful efforts from exploration wells drilled in the Burkett and Utica Shales. In the Illinois Basin, we successfully booked estimated proved reserves as a result of our ASP pilot, which were classified as extensions and discoveries. For the year ended December 31, 2010 we had significant extensions, discoveries of 3.5 MMBOE for oil and NGLs and 93.2 Bcfe for natural gas. These additions were primarily due to the additional proved undeveloped locations that were added to our proved reserve estimates that were a result of our continued drilling success in the Marcellus Shale. Extensions, discoveries and other additions for the year ended December 31, 2009 of 0.9 MMBOE of oil and NGLs and 18.4 Bcfe of natural gas include increases in proved undeveloped locations as a result of our successful exploration efforts in the Marcellus Shale in conjunction with the change in the SEC’s rules to allow producers in continuous accumulation plays to report additional undrilled locations beyond one offset on each side of a horizontal producing well.

23. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

FASB ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proved reserves. We followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of estimated proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0% annual discount factor.

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The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth our future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2011, 2010 and 2009 ($ in thousands):

	2011			2010			2009
Future Cash Inflows	$	2,333,513	(a)	$	1,335,068	(b)	$	844,811	(c)
Future Costs:
Production		(880,077	)		(542,814	)		(370,212	)
Abandonment		(65,560	)		(63,637	)		(63,333	)
Development		(251,821	)		(152,965	)		(86,819	)
Net Future Cash Inflow Before Income Taxes		1,136,055			575,652			324,447
Future Income Tax Expense		(277,568	)		(139,482	)		(53,703	)
Total Future Net Cash Flows Before 10.0% Discount		858,487			436,170			270,744
Less: Effect of a 10.0% Discount Factor		(444,552	)		(248,105	)		(126,365	)
Standardized Measure of Discounted Future Net Cash Flows	$	413,935		$	188,065		$	144,379

(a) Calculated using weighted average prices of $4.55 per Mcf, $92.45 per barrel of oil and $46.34 per barrel of NGLs

(b) Calculated using weighted average prices of $4.57 per Mcf, $76.03 per barrel of oil and $31.71 per barrel of NGLs

(c) Calculated using weighted average prices of $3.87 per Mcf and $57.65 per barrel of oil and NGLs

For purposes of consistency with 2011 calculations, we have revised certain amounts relating to changes in the standard measure of discounted future net cash flows with no effect to the previously reported period end measures. The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	2011			2010			2009
Standardized Measure – Beginning of Period	$	188,065		$	144,379		$	68,945
Revisions of Previous Estimates:
Changes in Prices and Production Costs		29,223			33,083			35,466
Revisions in Quantities		40,525			(36,541	)		90,475
Changes in Future Development Costs		(19,539	)		(46,082	)		32,431

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Accretion of Discount and Timing of Future Cash Flows		25,218			17,438			6,895
Net Change in Income Tax (a)		(42,875	)		(34,117	)		(30,000	)
Purchase (Sale) of Reserves in Place		0			(10,438	)		0
Plus Extensions, Discoveries, and Other Additions		159,047			44,135			5,715
Development Costs Incurred		61,290			24,825			12,211
Sales of Product – Net of Production Costs		(78,763	)		(42,568	)		(26,376	)
Changes in Timing and Other		51,744			93,951			(51,383	)
Standardized Measure – End of Period	$	413,935		$	188,065		$	144,379

24. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Results of operations are equal to revenues, less (a) production costs, (b) impairment expenses, (c) exploration expenses, (d) DD&A expenses, and (e) income tax expense (benefit):

	2011		2010		2009
Consolidated Entities (in thousands):
Revenues
Oil and Natural Gas Sales	$	111,879	$	67,224	$	48,534
Expenses
Production and Lease Operating Expense		33,116		24,656		22,157
Impairment Expense		14,631		8,863		1,625
Exploration Expense		2,507		2,578		2,080
Depletion, Depreciation, Amortization and Accretion		28,361		21,806		25,205
Total Costs		78,615		57,903		51,067
Pre-tax Operating Income (Loss)		33,264		9,321		(2,533	)
Income Tax Expense (Benefit) (a)		10,445		3,850		(1,008	)
Results of Operations for Oil and Gas Producing Activities (b)	$	22,819	$	5,471	$	(1,525	)
Share of Equity Method Investments (in thousands):

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Expenses
Depletion, Depreciation, Amortization and Accretion	$	1,568		$	181		$	0
Total Costs		1,568			181			0
Pre-tax Operating Loss		(1,568	)		(181	)		0
Income Tax Benefit (a)		(519	)		(75	)		0
Results of Operation for Oil and Gas Producing Activities	$	(1,049	)	$	(106	)	$	0
Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities	$	21,770		$	5,365		$	(1,525	)

(a) Computed using the effective tax rate for each period: 31.4% in 2011; 41.3% in 2010 and; 39.8% in 2009.

25. LITIGATION

Illinois Basin EPA Consent Decree

In September 2006, the United States Department of Justice (“DOJ”), the United States Environmental Protection Agency (“EPA”) and the State of Illinois initiated an enforcement action against us seeking mandatory injunctive relief and potential civil penalties based on allegations that we (and various predecessor companies) were violating the Clean Air Act in connection with the release of hydrogen sulfide gas and volatile organic compounds (“VOC’s”) in the course of our oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. In June 2007, the United States District Court for the Southern District of Illinois granted the United States’ motion for approval and entry of a proposed consent decree, thereby resolving the enforcement action according to the terms described in the consent decree. The consent decree required us to take certain remedial actions to reduce hydrogen sulfide and VOC emissions and monitor the same. The consent decree did not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.

In January 2010, we submitted certain proposed revisions to a Directed Inspection and Maintenance Plan previously implemented by us pursuant to the terms of the consent decree. In general, the proposed revisions update the plan to reflect changes in hydrogen sulfide control measures and procedures implemented in the field and changes in procedures for responding to resident complaints of hydrogen sulfide odors. The EPA, DOJ and Illinois EPA all approved these revisions.

Settlement Agreement—Illinois Class Action Litigation

We were a defendant in a class action lawsuit filed in the United States District Court for the Southern District of Illinois. This action was commenced in October 2006, by plaintiffs Julia Leib and Lisa Thompson, individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport and

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Petrolia, Illinois. The complaint asserted several causes of action, including violation of the Resource Conservation and Recovery Act, Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct.

In December 2009, we entered into a Settlement Agreement and Release (the “Settlement Agreement”) with Leib and Thompson, individually and on behalf of a certified class, to settle the class action lawsuit. Under the terms of the Settlement Agreement, without any admission of liability, we agreed to pay the class a total of $1.9 million. Pursuant to the terms of a pollution liability policy, $1.0 million of the settlement payment was funded by our insurance carrier. Pursuant to the Settlement Agreement, we also agreed to permanently plug four inactive oil wells. In return for the above consideration, each member of the class released all claims against us that in any way related to hydrogen sulfide or other environmental conditions in the class area that were the subject of, or could have been the subject of, the claims alleged in the class action lawsuit. In addition, each class member released any claims related to any future releases of hydrogen sulfide in the class area on the condition that we substantially comply with the terms and conditions of the consent decree describe above in “Illinois Basin EPA Consent Decree”. The Settlement Agreement did not provide for a release of any potential individual claims of other class members since those claims were not the subject of the class action lawsuit. The Settlement Agreement became effective in April 2010.

Litigation Related to Proposed Oil and Gas Leases in Westmoreland and Clearfield Counties, Pennsylvania

In July 2009, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Westmoreland County, Pennsylvania (the “Snyder Case”). The named plaintiffs were five individuals who sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Snyder Case generally asserted that a binding contract to lease oil and gas property was formed between the Company and each proposed class member when representatives of Duncan Land & Energy, Inc. (“Duncan Land”), a leasing agent that we engaged, presented a form of proposed oil and gas lease to each person, and each person signed the proposed oil and gas lease form and delivered the executed proposed lease to representatives of

Duncan Land. We rejected these leases and never signed them. The plaintiffs sought a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees.

In May 2011, we entered into a Settlement Agreement with respect to these legal proceedings. In July 2011, the court approved the Settlement Agreement, pursuant to which we offered each eligible class member an oil and gas lease, in a form agreed to by the parties, with a prepaid rental of $2,500 per acre for a five-year term with a 15% royalty. We also agreed to pay $30,000 to plaintiffs’ attorneys for the anticipated expenses of administration of the Settlement Agreement. Additionally, we deposited $2.5 million into a fund for distribution to class members and for attorney’s fees, costs and expenses of counsel for the class. The final order regarding the Settlement Agreement dismissed all claims against us

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with prejudice and without any admission of liability, and provided a release by all class members of all claims against us in connection with the litigation.

In June 2009, we were also named as a defendant in a lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Liegey Case”). The Liegey Case was brought by eight individuals involving oil and gas leasing activity in Clearfield County, Pennsylvania. The complaint in the Liegey Case asserts similar claims and requests for relief as those made in the Snyder Case described above. In June 2010, we settled the case and in July 2010, the court dismissed the case.

Litigation Related to Proposed Oil and Gas Leases in Clearfield County, Pennsylvania

In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale Case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale Case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them. The plaintiffs seek a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. The lawsuit is in the preliminary stages of discovery and we intend to vigorously defend against the claims. We are in the process of gathering data and executing our defense and we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses.

26. SUBSEQUENT EVENTS

Public Offering of Common Stock

On February 6, 2012, we completed an underwritten public offering of 8,050,000 shares of our common stock, which included 1,050,000 shares of common stock issued upon the full exercise of the underwriters’ over-allotment option, at a public offering price of $9.25 per share. The net proceeds of the transaction are expected to be approximately $70.6 million, after deducting underwriting discounts, commissions and estimated offering expense. We have used the proceeds of the offering to repay borrowings under our Senior Credit Facility.

Senior Credit Facility

On May 7, 2012, we entered into an amendment to the Senior Credit Facility to increase the borrowing base to $265.0 million from $255.0 million. On September 30, 2012, we entered into an amendment to the Senior Credit Facility to increase the borrowing base under to $290.0 million from $265.0 million.

Sale of Interest in Keystone Midstream

On May 29, 2012, we closed the sale of our ownership in Keystone Midstream, which we had accounted for as an equity method investment. The base consideration for the sale was $483.2 million after adjustments for closing cash, working capital and outstanding debt. Our net proceeds at closing totaled $121.4 million, net of $3.3 million for our share of transactional costs which were recorded as Gain (Loss) on Equity Method Investments on our Consolidated Statement of Operations. We have used the proceeds to pay down amounts outstanding under our Senior Credit Facility and for working capital. The amount received at closing excluded approximately $14.3 million to be held in escrow and paid out over the course of the next twelve months. We will recognize the escrow amount in income as it is received. Also included in the proceeds at closing was approximately $3.8 million funded by other sellers in the transaction as consideration for our entry into an amendment to our gas gathering, compression and processing agreement. This consideration is primarily recorded as Other Deposits and Liabilities on our Consolidated Balance Sheet and will be recognized in earnings over the term of the gas gathering, compression and processing agreement. We recognized a gain on the sale of our investment in Keystone Midstream of approximately $92.7 million, which was recorded as Other Income (Expense) in our Consolidated Statement of Operations.

DJ Basin

During October 2012, we sold 100% of our acreage holdings in the states of Nebraska and Colorado for proceeds of approximately $3.6 million. The carrying value of these holdings as of September 30, 2012 was approximately $1.3 million and was classified as Assets Held for Sale on our Consolidated Balance Sheet. Subsequent to the sale of these holdings, approximately $9.1 million in carrying value remains on our Consolidated Balance Sheet and classified as Assets Held for Sale for acreage holdings in the state of Wyoming.

Ethane Transportation Agreement

During October 2012, we entered into an ethane transportation agreement with Enterprise Liquids Pipeline LLC (“Enterprise”) to transport ethane produced in our Butler County, Pennsylvania operated area from certain delivery points to a natural gas storage complex at Mont Belvieu in the state of Texas where it will ultimately be marketed and sold. During the term of the agreement we are obligated to provide from 3,000 barrels of ethane per day, at a minimum, to 11,000 barrels of ethane per day, at a maximum, and pay a fee for any shortfalls of these volumes. The term of the agreement is expected to begin in July 2014 and ending in June 2029. In the event that we do not provide any ethane for transportation, we may be obligated to pay approximately $0 in 2012, $0 in 2013, $3.6 million in 2014, $10.7 million in 2015, $17.8 million in 2016 and $324.3 million thereafter. These amounts are determined based on current agreement transportation rates. In connection with the entry into the transportation agreement, we concurrently entered into a guaranty agreement whereby we have guaranteed the payment of obligations under the transportation agreement up to a maximum of $356.3 million.

27. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following tables set forth unaudited financial information on a quarterly basis for each of the last two years.

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

($ and Shares in Thousands Except per Share Data)

	2011
	March			June			September			December
Revenues	$	23,147		$	29,023		$	30,755		$	31,681
Costs and Expenses		30,749			25,539			38,901			34,795
Net Income (Loss) From Continuing Operations		(3,533	)		7,797			12,666			1,149
Net Loss From Discontinued Operations		(4,069	)		(4,313	)		(20,812	)		(4,263	)
Net Income (Loss)		(7,602	)		3,484			(8,146	)		(3,114	)
Net Income (Loss) Attributable to Noncontrolling Interests		(102	)		44			44			7
Net Income (Loss) Attributable to Rex Energy	$	(7,500	)	$	3,440		$	(8,190	)	$	(3,121	)
Income (Loss) per Common Share Attributable to Rex Common Shareholders:
Basic – Continuing Operations	$	(0.08	)	$	0.18		$	0.29		$	0.03
Basic – Discontinued Operations		(0.09	)		(0.10	)		(0.47	)		(0.10	)
Basic – Net Loss	$	(0.17	)	$	0.08		$	(0.18	)	$	(0.07	)
Basic – Weighted Average Shares Outstanding		43,862			43,880			43,951			44,026
Diluted – Continuing Operations	$	(0.08	)	$	0.18		$	0.29		$	0.03
Diluted – Discontinued Operations		(0.09	)		(0.10	)		(0.47	)		(0.10	)
Diluted – Net Loss	$	(0.17	)	$	0.08		$	(0.18	)	$	(0.07	)
Diluted – Weighted Average Shares Outstanding		43,862			44,451			44,384			44,567

	2010
	March			June			September			December
Revenues	$	16,758		$	15,686		$	16,856		$	19,463
Costs and Expenses		14,766			14,873			7,316			26,025
Net Income (Loss) From Continuing Operations		2,045			1,228			9,867			(5,335	)
Net Loss From Discontinued Operations		(53	)		(415	)		(327	)		(1,227	)
Net Income (Loss)		1,992			813			9,540			(6,562	)
Net Loss Attributable to Noncontrolling Interests		(56	)		(64	)		(88	)		(45	)

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Net Income (Loss) Attributable to Rex Energy	$	2,048	$	877		$	9,628		$	(6,517	)
Income (Loss) per Common Share Attributable to Rex Common Shareholders:
Basic – Continuing Operations	$	0.05	$	0.03		$	0.23		$	(0.12	)
Basic – Discontinued Operations		0.00		(0.01	)		(0.01	)		(0.03	)
Basic – Net Loss	$	0.05	$	0.02		$	0.22		$	(0.15	)
Basic – Weighted Average Shares Outstanding		42,106		43,710			43,698			43,586
Diluted – Continuing Operations	$	0.05	$	0.03		$	0.23		$	(0.12	)
Diluted – Discontinued Operations		0.00		(0.01	)		(0.01	)		(0.03	)
Diluted – Net Loss	$	0.05	$	0.02		$	0.22		$	(0.15	)
Diluted – Weighted Average Shares Outstanding		42,200		44,117			44,103			44,002

	2009
	March			June			September			December
Revenues	$	8,830		$	11,541		$	13,055		$	15,265
Costs and Expenses		10,179			20,978			14,241			19,861
Net Loss From Continuing Operations		(1,349	)		(9,437	)		(1,186	)		(4,596	)
Net Income From Discontinued Operations		323			—			—			—
Net Loss		(1,026	)		(9,437	)		(1,186	)		(4,596	)
Net Loss Attributable to Noncontrolling Interests		—			—			—			(12	)
Net Loss Attributable to Rex Energy	$	(1,026	)	$	(9,437	)	$	(1,186	)	$	(4,584	)
Earnings per Common Share Attributable to Rex Common Shareholders:
Basic – Continuing Operations	$	(0.04	)	$	(0.26	)	$	(0.03	)	$	(0.12	)
Basic – Discontinued Operations		0.01			—			—			—
Basic – Net Loss	$	(0.03	)	$	(0.26	)	$	(0.03	)	$	(0.12	)
Basic – Weighted Average Shares Outstanding		36,726			36,846			36,844			36,818
Diluted – Continuing Operations	$	(0.04	)	$	(0.26	)	$	(0.03	)	$	(0.12	)
Diluted – Discontinued Operations		0.01			—			—			—
Diluted – Net Loss	$	(0.03	)	$	(0.26	)	$	(0.03	)	$	(0.12	)
Diluted – Weighted Average Shares Outstanding		36,726			36,846			36,844			36,818

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