Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files) Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). Check One:

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of sections 27A of the Securities Act of 1933, as amended, and 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this report, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans and objectives of management for future operations, are forward-looking statements. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe” or “continue” or the negative thereof or similar terminology.

These forward-looking statements are subject to numerous assumptions, risks and uncertainties. Factors which may cause our actual results, performance or achievements to be materially different from those expressed or implied by us in forward-looking statements include, among others, the following:

Because these statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. You are cautioned not to place undue reliance on forward looking-statements, which speak only as of the date of this report. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

	September 30, 2014 (unaudited)			December 31, 2013
ASSETS
Current Assets
Cash and Cash Equivalents	$	87,622		$	1,900
Accounts Receivable		53,393			38,863
Taxes Receivable		504			5,189
Short-Term Derivative Instruments		7,257			5,668
Current Deferred Tax Asset		2,837			3,451
Inventory, Prepaid Expenses and Other		3,245			2,207
Total Current Assets		154,858			57,278
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,012,467			749,680
Unevaluated Oil and Gas Properties		334,461			189,385
Other Property and Equipment		83,645			70,115
Wells and Facilities in Progress		116,979			76,545
Pipelines		15,875			7,678
Total Property and Equipment		1,563,427			1,093,403
Less: Accumulated Depreciation, Depletion and Amortization		(255,471	)		(190,521	)
Net Property and Equipment		1,307,956			902,882
Deferred Financing Costs and Other Assets – Net		17,586			11,993
Equity Method Investments		18,098			18,708
Long-Term Derivative Instruments		430			535
Total Assets	$	1,498,928		$	991,396
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	56,569		$	31,103
Current Maturities of Long-Term Debt		8,248			6,743
Accrued Liabilities		70,835			54,450
Short-Term Derivative Instruments		1,321			4,663
Total Current Liabilities		136,973			96,959
8.875% Senior Notes Due 2020		350,000			350,000
6.25% Senior Notes Due 2022		325,000			—
Premium on Senior Notes, Net		2,816			3,078
Senior Secured Line of Credit and Long-Term Debt		6,385			62,191
Long-Term Derivative Instruments		945			1,765
Long-Term Deferred Tax Liability		43,414			29,446
Other Deposits and Liabilities		4,303			4,992
Future Abandonment Cost		27,434			26,040
Total Liabilities	$	897,270		$	574,471
Commitments and Contingencies (See Note 13)
Stockholders’ Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 16,100 issued and outstanding on September 30, 2014 and 0 shares issued outstanding on December 31, 2013	$	1		$	—
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 54,116,652 shares issued and outstanding on September 30, 2014 and 54,186,490 shares issued and outstanding on December 31, 2013		54			54
Additional Paid-In Capital		616,384			456,554
Accumulated Deficit		(19,083	)		(41,725	)
Rex Energy Stockholders’ Equity		597,356			414,883
Noncontrolling Interests		4,302			2,042
Total Stockholders’ Equity		601,658			416,925
Total Liabilities and Stockholders’ Equity	$	1,498,928		$	991,396

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	73,448		$	58,063		$	227,650		$	150,447
Field Services Revenue		13,070			4,847			41,462			15,193
Other Revenue		18			64			92			164
TOTAL OPERATING REVENUE		86,536			62,974			269,204			165,804
OPERATING EXPENSES
Production and Lease Operating Expense		27,657			17,203			69,303			43,695
General and Administrative Expense		10,409			8,826			30,039			24,404
Loss on Disposal of Asset		84			140			385			1,632
Impairment Expense		1			2,244			41			2,414
Exploration Expense		1,462			3,242			4,890			7,511
Depreciation, Depletion, Amortization and Accretion		27,364			16,267			69,014			40,367
Field Service Operating Expense		9,547			3,652			30,912			10,354
Other Operating Expense (Income)		(24	)		19			3			910
TOTAL OPERATING EXPENSES		76,500			51,593			204,587			131,287
INCOME FROM OPERATIONS		10,036			11,381			64,617			34,517
OTHER EXPENSE
Interest Expense		(11,080	)		(6,181	)		(25,718	)		(16,013	)
Gain (Loss) on Derivatives, Net		12,316			(4,624	)		2,315			(1,423	)
Other Income (Expense)		(12	)		(30	)		(30	)		2,041
Loss on Equity Method Investments		(202	)		(207	)		(610	)		(569	)
TOTAL OTHER INCOME (EXPENSE)		1,022			(11,042	)		(24,043	)		(15,964	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX		11,058			339			40,574			18,553
Income Tax (Expense) Benefit		(4,469	)		1,493			(14,592	)		(5,622	)
NET INCOME FROM CONTINUING OPERATIONS		6,589			1,832			25,982			12,931
Income From Discontinued Operations, Net of Income Taxes		—			—			—			460
NET INCOME		6,589			1,832			25,982			13,391
Net Income Attributable to Noncontrolling Interests		895			258			3,340			912
NET INCOME ATTRIBUTABLE TO REX ENERGY	$	5,694		$	1,574		$	22,642		$	12,479
Earnings per common share:
Basic – Net Income From Continuing Operations Attributable to Rex Energy Common Shareholders	$	0.11		$	0.03		$	0.42		$	0.23
Basic – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders		—			-			—			0.01
Basic – Net Income Attributable to Rex Energy Common Shareholders	$	0.11		$	0.03		$	0.42		$	0.24
Basic – Weighted Average Shares of Common Stock Outstanding		53,214			52,626			53,493			52,560
Diluted – Net Income From Continuing Operations Attributable to Rex Energy Common Shareholders	$	0.10		$	0.03		$	0.41		$	0.23
Diluted – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders		—			-			—			0.01
Diluted – Net Income Attributable to Rex Energy Common Shareholders	$	0.10		$	0.03		$	0.41		$	0.24
Diluted – Weighted Average Shares of Common Stock Outstanding		57,991			53,293			55,254			53,124

CONSOLIDATED STATEMENT OF CHANGES IN NONCONTROLLING INTERESTS AND STOCKHOLDERS’ EQUITY

	Common Stock					Preferred Stock
	Shares			Par Value		Shares		Par Value		Additional Paid-In Capital		Accumulated Deficit			Rex Energy Stockholders' Equity		Noncontrolling Interests			Total Stockholders’ Equity
BALANCE December 31, 2013		54,186		$	54		-	$	-	$	456,554	$	(41,725	)	$	414,883	$	2,042		$	416,925
Non-Cash Compensation		—			—		—		—		4,398		—			4,398		—			4,398
Issuance of Restricted Stock, Net of Forfeitures		(106	)		—		—		—		—		—			—		—			—
Stock Option Exercise		37			—		—		—		421		—			421		—			421
Issuance of Preferred Stock		—			—		16		1		155,011		—			155,012		—			155,012
Capital Distributions		—			—		—		—		—		—			—		(1,080	)		(1,080	)
Net Income		—			—		—		—		—		22,642			22,642		3,340			25,982
BALANCE September 30, 2014		54,117		$	54		16	$	1	$	616,384	$	(19,083	)	$	597,356	$	4,302		$	601,658

	For the Nine Months Ended September 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	25,982		$	13,391
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		610			569
Non-cash Expenses		5,146			4,432
Depreciation, Depletion, Amortization and Accretion		69,014			40,367
(Gain) Loss on Derivatives		(2,315	)		1,423
Cash Settlements of Derivatives		(3,331	)		5,540
Dry Hole Expense		237			485
Deferred Income Tax Expense		14,592			10,970
Impairment Expense		41			2,414
Loss on Sale of Asset		385			663
Changes in operating assets and liabilities
Accounts Receivable		(9,854	)		(7,028	)
Inventory, Prepaid Expenses and Other Assets		(1,038	)		(391	)
Accounts Payable and Accrued Liabilities		36,060			34,750
Other Assets and Liabilities		(1,966	)		(1,830	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		133,563			105,755
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		210			246
Contributions to Equity Method Investments		—			(2,493	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		412			3,931
Acquisitions of Undeveloped Acreage		(153,628	)		(31,458	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(310,353	)		(197,264	)
NET CASH USED IN INVESTING ACTIVITIES		(463,359	)		(227,038	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit		(248,146	)		(1,022	)
Proceeds from Long-Term Debt and Line of Credit		193,041			1,750
Repayments of Loans and Other Notes Payable		(1,998	)		(1,363	)
Proceeds from Senior Notes, Net of Discounts and Premiums		325,000			105,000
Debt Issuance Costs		(6,731	)		(3,004	)
Proceeds from the Issuance of Preferred Stock, Net		155,011			—
Proceeds from the Exercise of Stock Options		421			534
Distributions by the Partners of Consolidated Joint Ventures		(1,080	)		(646	)
Purchase of Noncontrolling Interests		—			(150	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		415,518			101,099
NET INCREASE (DECREASE) IN CASH		85,722			(20,184	)
CASH – BEGINNING		1,900			43,975
CASH – ENDING	$	87,622		$	23,791
SUPPLEMENTAL DISCLOSURES
Interest Paid		18,123			15,313
Cash Received for Income Taxes		(4,643	)		(4,976	)
NON-CASH ACTIVITIES
Increase in Accrued Liabilities		7,042			30,455

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent oil, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian and Illinois Basins. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. In the Illinois Basin, we are focused on developmental oil drilling and the implementation of enhanced oil recovery (“EOR”) on our properties. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. In addition to our drilling and exploration activities, we are also engaged in oil and gas field services, where we provide water sourcing, water disposal and water transfer capabilities for completion operations.

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.

The interim Consolidated Financial Statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Actual results may differ from those estimates and results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in prices for crude oil, NGLs and natural gas, future commodity prices for financial derivative instruments, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market consumption, interruption in production, our ability to obtain additional capital, and the success of oil, NGL and natural gas recovery techniques.

Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2013.

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, for which the final sale was completed in 2013. Pursuant to the rules for discontinued operations, 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 results from our discontinued operations. For additional information see Note 4, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

We have two principal reportable segments, which are segregated based on the products and services that each provides: (a) exploration and production, and (b) field services. Our exploration and production segment engages in the exploration, acquisition, development and production of oil, NGLs and natural gas. We have a single, company-wide management team that oversees all properties as a whole rather than isolating operating segments; however, we do track basic operational data by area. Our financial performance is measured as a single enterprise and not by individual area. Our field services segment operates and manages water sourcing, water transfer, equipment rental, trucking and water disposal services, primarily in the Appalachian Basin. Our field services segment is comprised of operations that have economic characteristics that are distinct from those of our exploration and production segment and is managed by its own unique management team.

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 the three and nine months ended September 30, 2014 and 2013:

($ in Thousands)	Exploration and Production		Field Services			Intercompany Eliminations			Consolidated Total
Three Months Ended September 30, 2014
Revenues	$	73,466	$	15,870		$	(2,800	)	$	86,536
Inter-Segment Revenues		—		(2,800	)		2,800			—
Total Revenues		73,466		13,070			—			86,536
Income (Loss) From Continuing Operations, Before Income Taxes	$	9,503	$	2,225		$	(670	)	$	11,058
Three Months Ended September 30, 2013
Revenues	$	58,127	$	6,543		$	(1,696	)	$	62,974
Inter-Segment Revenues		—		(1,696	)		1,696			—
Total Revenues		58,127		4,847			—			62,974
Income (Loss) From Continuing Operations, Before Income Taxes	$	192	$	629		$	(482	)	$	339
Nine Months Ended September 30, 2014
Revenues	$	227,742	$	54,467		$	(13,005	)	$	269,204
Inter-Segment Revenues		—		(13,005	)		13,005			—
Total Revenues		227,742		41,462			—			269,204
Income (Loss) From Continuing Operations, Before Income Taxes	$	35,434	$	8,306		$	(3,166	)	$	40,574
Nine Months Ended September, 2013
Revenues	$	150,611	$	19,668		$	(4,475	)	$	165,804
Inter-Segment Revenues		—		(4,475	)		4,475			—
Total Revenues		150,611		15,193			—			165,804
Income (Loss) From Continuing Operations, Before Income Taxes	$	16,464	$	3,344		$	(1,255	)	$	18,553
As of September 30, 2014
Total Assets	$	1,471,683	$	35,681		$	(8,436	)	$	1,498,928
As of December 31, 2013
Total Assets	$	971,973	$	26,266		$	(6,843	)	$	991,396

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 future abandonment cost changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.

Accretion expense totaled approximately $1.3 million and $2.9 million for the three and nine months ended September 30, 2014, respectively, and $1.2 million and $2.3 million for the three and nine months ended September 30, 2013, respectively. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells.

¹ Includes approximately $3.6 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

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. During 2012, we sold various parcels of acreage throughout our DJ Basin holdings at varying prices, much of which was lower than the existing carrying value of similar remaining acreage at the time of sale. During the first quarter of 2013, we entered an agreement to sell our remaining DJ Basin assets for $3.1 million. This transaction closed during the second quarter of 2013 and resulted in a gain of approximately $1.0 million. Since that time, we have had no assets or liabilities related to the DJ Basin or continuing cash flows from this 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.

	Three Months Ended September 30,				Nine Months Ended September 30,
($ in Thousands)	2014		2013		2014		2013
Revenues:
Oil, Natural Gas and NGL Sales	$	—	$	—	$	—	$	25
Total Operating Revenue		—		—		—		25
Costs and Expenses:
Production and Lease Operating Expense		—		—		—		104
General and Administrative Expense		—		—		—		23
Exploration Expense		—		—		—		97
Other Income Expense		—		—		—		(3	)
Gain on Sale of Asset		—		—		—		(969	)
Total Costs and Expenses		—		—		—		(748	)
Income from Discontinued Operations Before Income Taxes		—		—		—		773
Income Tax Expense		—		—		—		(313	)
Income from Discontinued Operations, net of taxes	$	—	$	—	$	—	$	460
Production:
Crude Oil (Bbls)		—		—		—		356
Total (Mcfe)		—		—		—		2,136

On September 9, 2014, we completed the acquisition of approximately 208,000 gross (207,000 net) acres prospective for the Marcellus, Upper Devonian/Burkett and Utica Shales from SWEPI, LP, an affiliate of Royal Dutch Shell, plc (“Shell”), for approximately $120.6 million in cash, after customary closing adjustments. Included in the acquisition were several producing wells and properties in various stages of development. The assets acquired are located in Armstrong, Beaver, Butler, Lawrence, Mercer and Venango counties in Pennsylvania and Columbiana and Mahoning counties in Ohio. The acquisition does not meet the definition of a business combination and, therefore, has been accounted for as an asset acquisition. The acquisition price was allocated as follows:

In April 2014, the FASB issued ASU 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposal of Components of an Entity. The amendments in this ASU change the criteria for reporting discontinued operations while enhancing the disclosures in this area. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization’s operations and financial results. In addition, the new guidance requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income and expenses of discontinued operations. The amendments in this ASU are effective in the first quarter of 2015 for public organizations with calendar year ends. We are currently evaluating the potential effect of this ASU but do not believe that it will have a material impact on our Consolidated Financial Statements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The amendments in this ASU affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards. This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services by following five steps:

An entity should apply the amendments in this ASU using one of the following two methods:

For public entities, the amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. We are currently evaluating the potential impact of this ASU.

In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation. The amendments in this ASU require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. A reporting entity should apply existing guidance in Topic 718 as it relates to awards with performance conditions that affect vesting to account for such awards. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. Entities may apply the amendments in this ASU either: (a) prospectively to all awards granted or modified after the effective date; or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new awards thereafter. The amendments in this ASU are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. We are currently evaluating the potential effect of this ASU but do not believe that it will have a material impact on our Consolidated Financial Statements.

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 counterparties 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 high-quality counterparties. Our counterparties are investment grade financial institutions and lenders in our Senior Credit Facility (see Note 8, Long-term Debt, to our Consolidated Financial Statements). 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 cash settlement date. For additional information, see Note 9, Fair Value of Financial 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. For the nine months ended September 30, 2014, approximately 95.5% of our commodity sales came from 5 purchasers, with the largest single purchaser accounting for 33.9% of commodity sales. We believe the continued growth in our Appalachian Basin operations will help us to minimize our future risks by diversifying our ratio of oil, NGLs and natural gas sales as well as the quantity of purchasers.

We maintain a revolving credit facility evidenced by a credit agreement, dated March 27, 2013 and most recently amended on September 12, 2014 (the “Senior Credit Facility”). As of September 30, 2014, the borrowing base under the Senior Credit Facility was $400.0 million; however, the Senior Credit Facility may be increased to up to $500.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed by the agreement. Within the Senior Credit Facility, a letter of credit subfacility exists for up to $60.0 million of letters of credit. The Senior Credit Facility provides that the borrowing base will be re-determined semi-annually by the lenders. As of September 30, 2014, loans made under the Senior Credit Facility were set to mature on September 12, 2019. 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 September 30, 2014, we had no outstanding borrowings, and at December 31, 2013, we had approximately $59.0 million of outstanding borrowings under the Senior Credit Facility.

At our election, borrowings under the Senior Credit Facility bear interest at a rate per annum equal to the “Adjusted LIBO Rate” or the “Alternate Base Rate” (each as defined below), plus, in each case, an applicable per annum margin. The “Adjusted LIBO Rate” is equal to the product of: (i) the London Interbank Offered Rate for deposits with a maturity comparable to the borrowings (the “LIBO Rate”) multiplied by (ii) the statutory reserve rate. The Alternative Base Rate is equal to the greater of: (i) RBC’s announced prime rate; (ii) the federal funds effective rate from time to time plus 0.5%; and (iii) Adjusted LIBO Rate for a one month interest period plus 1.0%. The applicable per annum margin, in the case of loans bearing interest at the Adjusted LIBO Rate, ranges from 150 to 250 basis points, and the applicable per annum margin, in the case of loans bearing interest at the Alternate Base Rate, ranges from 50 to 150 basis points, in each case, determined based upon our borrowing utilization at such date of determination. Upon the occurrence and continuance of an event of default, all outstanding loans shall bear interest at a rate equal to 200 basis points per annum plus the then effective rate of interest. Interest is payable on the last day of the relevant interest period (or at least every three months), in the case of loans bearing interest at the Adjusted LIBO Rate, and quarterly, in the case of loans bearing interest at the Alternate Base Rate.

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. As of September 30, 2014, we were in compliance with all of these metrics, and there were no existing defaults or events of default under our Senior Credit Facility.

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 7, Concentrations of Credit Risk, and Note 9, 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 Pennsylvania, Ohio, 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.

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 September 30, 2014 was approximately 4.0 to 1.0. Additionally, as of the last day of any fiscal quarter, our ratio of total debt to EBITDAX for the trailing twelve months must not exceed 4.25 to 1.0. Our ratio of total debt to EBITDAX as of September 30, 2014 was approximately 3.9 to 1.0.

As of September 30, 2014 and December 31, 2013, we had recorded on our Consolidated Balance Sheets approximately $352.8 million and $353.1 million of 8.875% senior notes due 2020 (the “2020 Senior Notes”), which is inclusive of a net premium of $2.8 million and $3.1 million, respectively. The amortization of our net premium during the first nine months of 2014, which follows the effective interest method, was approximately $0.3 million and was recorded as a credit to Interest Expense on our Consolidated Statement of Operations.

We may redeem, at specified prices, some or all of the 2020 Senior Notes at any time on or after December 1, 2016. We may also redeem up to 35% of the notes using the proceeds of certain equity offerings completed before December 1, 2015. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the 2020 Senior Notes from the holders.

On July 14, 2014, we issued a $325.0 million aggregate principal amount of 6.25% senior notes (the “2022 Senior Notes”) in a private offering at an issue price of 100.0% due to mature on August 1, 2022. The net proceeds of the 2022 Senior Notes, after discounts and expenses, were approximately $318.8 million. Debt issuance costs of $6.3 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the notes as Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually at a rate of 6.25% per annum on February 1 and August 1 of each year, commencing on February 1, 2015.

We may redeem, at specified redemption prices, some or all of the 2022 Senior Notes at any time on or after August 1, 2017. We may also redeem up to 35% of the notes using the proceeds of certain equity offerings completed before August 1, 2017. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the 2022 Senior Notes from the holders.

The Senior Notes due 2020 and the Senior Notes due 2022 (collectively, the “Senior Notes”) are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. In addition, there are no significant restrictions on our ability, or the ability of any subsidiary guarantor, to receive funds from our subsidiaries through dividends, loans, advances or otherwise. For additional information on our guarantor and non-guarantor subsidiaries, see Note 19, Condensed Consolidating Financial Information, to our Consolidated Financial Statements.

In addition to the Senior Credit Facility and the Senior Notes, 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 other obligations consisted of the following at September 30, 2014 and December 31, 2013:

On October 18, 2013, Water Solutions Holdings entered into agreements with M&T Bank (“M&T”) to obtain a revolving line of credit (“Demand Note”) and an equipment line of credit (“Equipment Term Note”).

The borrowing base for the Demand Note is the lesser of (a) $16.0 million, increased from $4.0 million at December 31, 2013, or (b) 80% of Water Solutions’ Accounts Receivable which are less than 90 days old. Borrowings under the Demand Note are to be used for working capital and general corporate purposes. At Water Solutions’ election, borrowings under the Demand Note bear interest per annum equal to an adjusted LIBOR rate or an adjusted base rate, as defined below. The adjusted LIBOR rate is equal 2.75 percentage points above the greater of (a) one-month LIBOR, adjusting daily, or (b) one-day LIBOR. The adjusted base rate is equal

to 2.0 percentage points above the rate of interest announced by M&T as its prime rate. All interest that is accrued through the last day of any calendar month will be due and payable by the tenth day of the next calendar month. While there is no stated maturity date for amounts outstanding under the Demand Note, in certain circumstances, Water Solutions may be required to repay amounts outstanding on demand from M&T. As of September 30, 2014, there was approximately $4.5 million outstanding under the Demand Note.

The Demand Note agreement does not contain any collateral requirements on behalf of Water Solutions, nor does it contain any financial covenant requirements.

Maximum borrowings under the Equipment Term Note are equal to $6.0 million and are to be used for purposes of making equipment or vehicle acquisitions up to a maximum of 80% of the costs of such assets. Borrowings under the Equipment Term Note bear interest per annum equal to the three month LIBOR plus 3.0 percentage points. All interest is due and payable on the first day of each fiscal quarter. Maturity dates will vary with each borrowing, but will generally be three to four years from the date of borrowing. In certain circumstances, Water Solutions may be required to prepay any loans that are outstanding. As of September 30, 2014, there was approximately $3.6 million outstanding under the Equipment Term Note.

The Equipment Term Note contains covenants that restrict Water Solutions’ ability to, among other things, materially change their business; incur indebtedness; make loans to others; incur liens; make investments; or become a guarantor. Borrowings under the Equipment Term Note are collateralized with liens covering 80% of the value of assets purchased with associated loans under the Equipment Term Note. The Equipment Term Note also requires that Water Solutions meet certain financial covenants regarding tangible net worth, fixed charge coverage ratio and a debt to EBITDA ratio (as defined in the Equipment Term Note). EBITDA is a non-GAAP financial measure used by the management of Water Solutions and by other users of Water Solutions’ financial statements, such as 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, amortization and other similar non-cash activity. The Equipment Term Note requires that tangible net worth (i) not be less than $2.5 million measured annually, and (ii) not be less than $2.5 million plus 30% of annual net income commencing with the fiscal year ended December 31, 2013 and each fiscal year thereafter. As of December 31, 2013, Water Solutions’ net worth was approximately $9.2 million. Also, Water Solutions’ fixed charge coverage ratio for four consecutive fiscal quarters ending at the end of each fiscal quarter shall not be less than 1.75 to 1.0. As of September 30, 2014, Water Solutions’ fixed charge coverage ratio was approximately 2.3 to 1.0. Water Solutions’ debt to EBITDA ratio for the trailing 12 month period ending on the last day of the measurement period shall not be greater than 2.25 to 1.0. As of September 30, 2014, Water Solutions’ debt to EBITDA ratio was approximately 1.0 to 1.0.

The following is the principal maturity schedule for debt outstanding as of September 30, 2014:

Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL 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 September 30, 2014 and December 31, 2013, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, calls, call protected swaps, basis swaps and three-way collars. 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.

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 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. Deferred put spread contracts are similar to three-way collars except that there is no maximum price ceiling established. Swaption agreements provide options to counterparties to extend swaps into subsequent years. Similar to a deferred put spread and a three-way collar, a cap swap provides a sold put in combination with a swap. Should prices fall below the sold put, we would receive the settlement price plus the differential between the sold put and the swap. Basis swaps are arrangements that guarantee a price differential from a specified delivery point. Currently, our basis swaps provide basis protection between Henry Hub and Dominion Appalachia pricing.

We enter into the majority of our derivative arrangements with five 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 7, Concentrations of Credit Risk, to our Consolidated Financial Statements.

None of our commodity derivatives are designated for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. We received net cash settlements of $3.0 million and paid net cash settlements of $4.2 million in relation to our commodity derivatives during the three and nine months ended September 30, 2014, respectively, and received net cash settlements of $0.7 million and $5.5 million in relation to our commodity derivatives for the three and nine months ended September 30, 2013, respectively.

As of September 30, 2014, we had over 85.0% and 20.0% of our annualized 2014 oil production hedged through the remainder of 2014 and 2015, respectively, over 75.0% and 45.0% of our annualized 2014 natural gas production hedged through the remainder of 2014 and 2015, respectively, and over 60.0% of our annualized 2014 NGL production hedged through the remainder of 2014. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future and completion or the natural decline of our oil and gas production.

We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of September 30, 2014 and December 31, 2013, we had $0.0 million and $59.0 million outstanding under our Senior Credit Facility, respectively, which is subject to variable rates of interest and $675.0 million of Senior Notes outstanding subject to a fixed interest rate. See Note 8, Long-Term Debt, to our Consolidated Financial Statements for additional information on our Senior Credit Facility and Senior Notes.

As of December 31, 2013, we had a $25.0 million notional fixed-to-variable interest rate swap to manage our interest rate exposure related to the Senior Notes. Prior to 2013, we did not have any interest rate swap agreements. During the second quarter of 2014, we terminated our interest rate swap for net proceeds of approximately $0.6 million. We utilized the mark-to-market accounting method to account for our interest rate swap. We recognized all gains and losses related to this contract in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. During 2013, there were no cash settlements related to our interest rate swap agreement. During the three and nine months ended September 30, 2014, we received cash payments of approximately $0.0 million and $0.9 million, respectively, related to our interest rate swaps. The fair value of our interest rate swap as December 31, 2013, was a liability of approximately $0.2 million.

The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013:

Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net asset of approximately $5.4 million and a net liability of approximately $0.2 million at September 30, 2014 and December 31, 2013, respectively.

Our open asset/(liability) financial commodity derivative instrument positions at September 30, 2014 consisted of:

Period	Volume	Put Option		Floor		Ceiling		Swap			Long Call		Fair Market Value ($ in Thousands)
Oil
2014—Collar	15,000 Bbls	$	—	$	90.00	$	97.65	$	—		$	—	$	26
2014—Cap Swap	90,000 Bbls		80.83		—		—		97.72			—		649
2014—Three Way Collar	90,000 Bbls		77.92		88.98		103.39		—			—		171
2014—Deferred Put Spread	42,000 Bbls		75.00		90.00		—		—			—		(146	)
2015—Three Way Collar	120,000 Bbls		78.75		89.06		100.44		—			—		292
2015—Call Protected Swap	30,000 Bbls		—		—		—		95.76			110.00		228
2015—Put	930,000 Bbls		—		90.16		—		—			—		235
	1,317,000 Bbls												$	1,455
Natural Gas
2014—Call	450,000 Mcf	$	—	$	—	$	5.00	$	—		$	—	$	(7	)
2014—Three Way Collar	4,050,000 Mcf		3.55		4.19		4.69		—			—		556
2014—Swap	1,110,000 Mcf		—		—		—		3.96			—		(147	)
2014—Collar	450,000 Mcf		—		3.51		4.43		—			—		(23	)
2014—Swaption	600,000 Mcf		—		—		—		4.45			—		(35	)
2014—Basis Swap	1,500,000 Mcf		—		—		—		(0.37	)		—		1,889
2014—Cap Swap	900,000 Mcf		3.30		—		—		4.09			—		(17	)
2015—Three Way Collar	12,900,000 Mcf		3.63		4.16		4.61		—			—		707
2015—Swap	1,200,000 Mcf		—		—		—		4.18			—		180
2015—Cap Swap	2,400,000 Mcf		3.28		—		—		4.10			—		(28	)
2015—Call	2,400,000 Mcf		—		—		4.40		—			—		(528	)
2015—Swaption	0 Mcf		—		—		—		4.47			—		(505	)
2015—Basis Swap	1,200,000 Mcf		—		—		—		(0.56	)		—		973
2016—Three Way Collar	2,100,000 Mcf		3.60		4.08		4.52		—			—		(127	)
2017—Three Way Collar	1,200,000 Mcf		3.60		4.10		4.57		—			—		(82	)
	32,460,000 Mcf												$	2,806
NGLs
2014—Swap	261,000 Bbls	$	—	$	—	$	—	$	56.63		$	—	$	819
2015—Swap	258,000 Bbls		—		—		—		44.60			—		341
	519,000 Bbls												$	1,160

The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013 is summarized below

	September 30			December 31,
($ in Thousands)	2014			2013
Short-Term Derivative Assets:
Crude Oil—Collars	$	26		$	380
Crude Oil—Cap Swap		649			—
Crude Oil—Call Protected Swap		228			—
Crude Oil—Put		235			—
Crude Oil—Three-Way Collars		463			104
NGL—Swaps		1,128			83
Natural Gas—Swaps		226			106
Natural Gas—Cap Swaps		103			5
Natural Gas—Basis Swaps		2,778			3,984
Natural Gas—Three-Way Collars		1,343			518
Natural Gas—Swaption		78			—
Interest Rate—Swap		—			488
Total Short-Term Derivative Assets	$	7,257		$	5,668
Long-Term Derivative Assets:
NGL—Swaps	$	61		$	—
Natural Gas—Cap Swaps		26			5
Natural Gas—Swaps		45			22
Natural Gas—Basis Swaps		84			339
Natural Gas—Three-Way Collars		214			169
Total Long-Term Derivative Assets	$	430		$	535
Total Derivative Assets	$	7,687		$	6,203
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	—		$	(42	)
Crude Oil—Swaps		—			(119	)
Crude Oil—Three-Way Collars		—			(29	)
Crude Oil—Deferred Put Spread		(146	)		(585	)
NGL—Swaps		(29	)		(995	)
Natural Gas—Three-Way Collars		(228	)		(125	)
Natural Gas—Collars		(23	)		(235	)
Natural Gas—Call		(403	)		(150	)
Natural Gas—Cap Swaps		(141	)		(496	)
Natural Gas—Swaption		(113	)		(717	)
Natural Gas—Swaps		(238	)		(1,170	)
Total Short - Term Derivative Liabilities	$	(1,321	)	$	(4,663	)
Long-Term Derivative Liabilities:
Natural Gas—Swaps	$	—		$	(4	)
Natural Gas—Cap Swaps		(33	)		(307	)
Natural Gas—Three-Way Collars		(275	)		—
Natural Gas—Swaption		(505	)		—
Natural Gas—Call		(132	)		(761	)
Interest Rate—Swap		—			(693	)
Total Long-Term Derivative Liabilities	$	(945	)	$	(1,765	)
Total Derivative Liabilities	$	(2,266	)	$	(6,428	)

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 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.

Our Level 2 fair value measurements are comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of September 30, 2014 and December 31, 2013, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.

Our Level 3 fair value measurements are comprised of our natural gas basis swap contracts. The fair values recorded as of September 30, 2014 were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. The significant unobservable input used in the fair value measurement of our natural gas basis swaps was the estimate of future natural gas basis differentials. Significant variations in price differentials could result in a significantly different fair value measurement.

The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of September 30, 2014 are included in the table below.

During the three and nine months ended September 30, 2014, there were no transfers into or out of Level 1 or Level 2 measurements.

The following table presents the fair value hierarchy table for assets and liabilities measured at fair value:

The value of our oil derivatives are comprised of collar, three-way collar, swap, cap swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair value of our oil derivatives as of September 30, 2014 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of puts, swaps, swaptions, collars, three way collars, basis swaps, cap swaps, and deferred put spreads contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of September 30, 2014 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of September 30, 2014 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. 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 those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments 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.

The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the nine months ended September 30, 2014 and 2013:

Changes in fair value on our Level 3 commodity derivative contracts outstanding for the nine months ended September 30, 2014 and 2013, resulted in a losses of approximately $4.3 million and $0.7 million, respectively. This amount has been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.

We report the fair value of future abandonment costs on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of future abandonment costs 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; estimated plugging costs; the credit-adjusted risk-free rate to be used; and inflation rates. The most significant inputs used in the determination of future abandonment costs are the estimated costs to plug and abandon our wells. Significant changes in the estimated cost to plug and abandon our wells can cause significant changes in the fair value measurement of our future abandonment costs due to the large number of wells that we operate. These inputs are unobservable, and thus result in a Level 3 classification. Refer to Note 3, Future Abandonment Cost, of our Consolidated Financial Statements for further information on future abandonment costs, which include a reconciliation of the beginning and ending balances.

The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:

The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy.

The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 1 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy.

The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the

period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.

For the nine months ended September 30, 2014, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to state taxes and permanent items, including section 162(m) limitations. For the nine months ended September 30, 2013, our overall effective tax rate on pretax losses from continuing operations was different than the statutory rate of 35% due primarily to changes in estimates of current and deferred state taxes identified when completing the state tax returns, permanent differences and changes in state tax rates.

Income tax payments made during the three and nine months ended September 30, 2014 and 2013 were negligible. We received tax refunds during the three and nine months ended September 30, 2014 of approximately $1.3 million and $4.7 million, respectively.

We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of September 30, 2014 and December 31, 2013, shares of common stock issued and outstanding totaled 54,116,652 and 54,186,490, respectively.

On August 18, 2014, we completed a registered offering of 16,100 shares of 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (the “Series A Preferred Stock”) that are represented by 1,610,000 depositary shares. The net proceeds of the offering were approximately $155.0 million, after deducting underwriting discounts, commissions and other offering expenses. We utilized a portion of the net proceeds to fund the acquisition of assets from Shell and intend to use the remaining proceeds to fund our capital expenditures program and for general corporate purposes.

The annual dividend on each share of the Series A Preferred Stock is 6.0% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on each February 15, May 15, August 15 and November 15 of each year, commencing on November 15, 2014.

We will pay cumulative dividends, when and if declared, in cash, stock or a combination therof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. No dividends had been declared as of September 30, 2014.

The Series A Preferred Stock is convertible at the option of the holder at an initial conversion rate of 555.56 shares of our common stock per share (5.5556 shares of our common stock per depositary share), equivalent to an initial conversion price of $18.00 per share of common stock. The conversion price represents a premium of approximately 25.2% relative to the NASDAQ Global Market closing sale price of our common stock on August 12, 2014 or $14.38 per share.

At any time on or after August 30, 2019, we may at our option cause all outstanding shares of the Series A Preferred Stock to be automatically converted into common stock at the then-applicable conversion price if the closing sale price of our common stock exceeds 130% of the then-prevailing conversion price for a specified period prior to the conversion. If a holder elects to convert shares of Series A Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to the converting holder.

Except as required by law or our Certificate of Incorporation, holders of the Series A Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). Until such arrearage is paid in full, the holders will be entitled to elect two directors and the number of directors on our board of directors will increase by that same number.

We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations 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 one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities.

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

All awards granted under the Plan have been issued at the closing price of our common stock on the NASDAQ Global Select Market on the date of the grant. All outstanding stock options have been awarded with five or ten year expiration dates at an exercise price equal to our closing price on the NASDAQ Global Select Market on the day the award was granted. 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 represent the right to purchase shares of common 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 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. During the three and nine months ended September 30, 2014 and 2013, we did not issue options to purchase shares of our common stock.

Stock-based compensation expense relating to stock options outstanding for the three and nine months ended September 30, 2014 and 2013 was negligible. 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 nine months ended September 30, 2014 and 2013, was approximately $0.3 million and $0.4 million, respectively. The total tax benefit was approximately $0.1 million and for $0.2 million each of the nine-month periods ended September 30, 2014 and 2013, respectively.

A summary of the status of our issued and outstanding stock options as of September 30, 2014 is as follows:

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at September 30, 2014 were 3.1 years and $1.1 million, respectively. The weighted average remaining contractual term and the aggregate intrinsic value for options exercisable at September 30, 2014 were 3.3 years and $1.1 million, respectively. As of September 30, 2014, unrecognized compensation expense related to stock options was negligible.

During the nine-month period ended September 30, 2014, the Compensation Committee approved the issuance of an aggregate of 51,178 shares of restricted common stock to 18 employees. During the nine-month period ended September 30, 2013, the Compensation Committee approved the issuance of an aggregate of 414,924 shares of restricted stock to 38 employees and four non-employees. The shares granted are subject to time vesting and, in some cases, 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 date upon which the shares are released. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. The restricted shares of common stock are valued at the closing price of our common stock on the NASDAQ Global Select Market on the date of grant. Upon a “change in control” of us, as such term is defined in the Plan, restrictions on time vesting and performance-based vesting restricted stock will lapse to varying degrees as outlined in each award agreement. Compensation expense associated with the restricted stock awards is recognized on a straight-line basis over the vesting period.

Certain of our outstanding restricted stock awards granted in 2014, 2013 and 2012 are subject to market-based vesting through a calculation of total shareholder return (“TSR”) of our common stock relative to a pre-defined peer group over a three-year period.

The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule:

The weighted average fair value of the TSR awards granted as of September 30, 2014 and December 31, 2013 were $10.15 and $12.59 per share, respectively. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:

The dividend yield of zero reflects the fact that we have never paid cash dividends on our common stock and have no present intentions of doing so. The risk-free interest rate reflects the U.S. Treasury Constant Maturity rates as of the measurement date, converted into an implied “spot rate” yield. Our expected volatility estimates are based on observed historical volatility of daily stock returns for the three-year period preceding the grant date. Market index is an equal-weight index of the companies in the peer group. Expected life is measured as the grant date through the end of the performance period. Performance and market 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. Compensation expense for the TSR awards is recognized on a straight-line basis over the vesting period.

Compensation expense associated with restricted stock awards totaled $1.6 million and $4.3 million for the three and nine-month periods ended September 30, 2014, respectively, and $1.2 million and $3.5 million for the three and nine-month periods ended September 30, 2013, respectively. As of September 30, 2014, total unrecognized compensation cost related to restricted common stock grants was approximately $6.5 million, which will be recognized over a weighted average period of 1.9 years.

A summary of the restricted stock activity for the nine months ended September 30, 2014 is as follows:

We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.

The accrual of reserves for legal matters is included in Accrued Liabilities on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently 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 our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

There have been no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013.

Due to the nature of the oil and natural gas 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 of our policies and properties to identify changes in the environmental risk profile. In these reviews we 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 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. As of September 30, 2014, we know of no significant probable or possible environmental contingent liabilities.

At September 30, 2014, we had posted $5.2 million in various letters of credit to secure our drilling and related operations.

As of September 30, 2014, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and nine months ended September 30, 2014 and 2013 was $0.3 million and $0.8 million in 2014, respectively, and $0.2 million and $0.5 million in 2013, respectively. Lease commitments by year for each of the next five years are presented in the table below:

We have a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest in Butler County, Pennsylvania to process our produced natural gas. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $4.8 million in 2014, $15.0 million in 2015, $25.8 million in 2016, $31.0 million in 2017, $31.0 million in 2018 and $245.7 million thereafter, assuming our average working interest in the region of approximately 70%. Charges incurred for processing capacity with MarkWest were negligible during the three and nine-month periods ended September 30, 2014 and 2013.

We have contracted drilling rig services on four rigs to support our Appalachian Basin operations. The minimum cost to retain these rigs would require payments of approximately $2.6 million in 2014, $3.9 million in 2015 and $1.5 million in 2016, which is consistent with our estimated working interest in this project area. We also have agreements for contracted completion services in the Appalachian Basin. The minimum cost to retain the completion services is approximately $2.6 million in 2014 and $5.1 million in 2015, which is consistent with our estimated working interest in this project area.

During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our oil, natural gas and NGLs. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $418.2 million, which is larger than our estimated minimum obligations due to certain contracts which have minimum commitment volumes and other contracts which contain provisions that require payment on all volumes delivered.

For the three months ended September 30, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $15.7 million and $7.6 million, respectively. For the nine months ended September 30, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $36.1 million and $17.6 million, respectively. Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:

In 2012, we entered into a drill-to-earn agreement with MFC Drilling, Inc. (“MFC”). Under the terms and conditions of the agreement, we will acquire a minimum, through a drill-to-earn structure, a 62.5% working interest in approximately 4,510 acres in Belmont, Guernsey and Noble Counties, Ohio. The agreement provides that in order for us to earn the 62.5% working interest, we will bear the cost for our 62.5% working interest and 100% of the 15% working interest of MFC until such time that we have met the $14.1 million drilling carry obligation. As of September 30, 2014, the remaining drilling carry obligation balance was approximately $4.8 million. Our 2014 capital budget includes additional development in this area.

In addition to the drilling carry obligation, we are required to meet drilling commitments. Amounts incurred toward the attainment of the drilling commitments are credited towards the drilling carry obligation. Our drilling commitments require us to commence the drilling of at least three Utica Shale wells by November 15 of each year until the carry obligation has been satisfied, with credits given to additional wells drilled beyond the annual commitment. We currently estimate the commitment for each well drilled and completed for our working interest and that of MFC to be approximately $8.0 million to $9.0 million. Should we not comply with the drilling commitments or terminate the agreement, we would be responsible for payment of any remaining drilling carry obligation at that time.

In 2012, Pennsylvania state legislators instituted a natural gas impact fee on producers of unconventional natural gas. The fee will be imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates:

^(a) Pricing utilized for determining annual fee is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31.

All fees owed will be due on April 1 of each year. For the three and nine months ended September 30, 2014 and 2013, we recorded expense of approximately $1.2 million, and $2.5 million in 2014, respectively and approximately $0.8 million, and $2.2 million in 2013. We record expenses related to the impact fees as Production and Lease Operating Expense.

In addition to the Asset Retirement Obligation discussed in Note 3, Future Abandonment Costs, to our Consolidated Financial Statements, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. These amounts totaled $0.1 million and $0.3 million at September 30, 2014 and December 31, 2013, respectively, and are included in Other Liabilities on our Consolidated Balance Sheets.

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, stock options and the effect of assumed conversions of preferred stock. Diluted income per common share includes the assumed exercise of stock options, assumed conversions of preferred stock 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 each of the three and nine-month periods ending September 30, 2014, stock options to purchase 0.3 million shares of common stock were outstanding but not included in the computation of diluted net income per share primarily due to the estimate of shares that would be repurchased using the treasury method. Performance-based restricted stock awards of 0.4 million shares and 0.7 million shares of common stock for the three and nine-month periods ended September 30, 2014, respectively, were outstanding but not included in the computations of diluted net income per share calculations due to performance metrics that have not yet been attained. For each of the three and nine-month periods ending September 30, 2013, stock options to purchase 0.3 million shares of common stock were outstanding but not included in the computation of diluted net income per share because the grant prices were greater than the average market price of the common shares. Performance-based restricted stock awards of 0.5 million shares of common stock for the three and nine months ended September 30, 2013, respectively, were outstanding but not included in the computations of diluted net income per share due to due to performance metrics that have not yet been attained. The following table sets forth the computation of basic and diluted earnings per common share:

(in thousands, except per share amounts)	Three Months Ended September 30,				Nine Months Ended September 30,
Numerator:	2014		2013		2014		2013
Net Income From Continuing Operations, Less Noncontrolling Interests	$	5,694	$	1,574	$	22,642	$	12,019
Net Income From Discontinued Operations		—		—		—		460
Net Income	$	5,694	$	1,574	$	22,642	$	12,479
Denominator:
Weighted Average Common Shares Outstanding - Basic		53,214		52,626		53,493		52,560
Effect of Dilutive Securities:
Employee Stock Options		111		164		134		137
Employee Performance-Based Restricted Stock Awards		485		503		218		427
Effect of Assumed Conversions of Preferred Stock		4,181		—		1,409		—
Weighted Average Common Shares Outstanding - Diluted		57,991		53,293		55,254		53,124
Earnings per Common Share:
Basic — Net Income From Continuing Operations	$	0.11	$	0.03	$	0.42	$	0.23
— Net Income From Discontinued Operations		—		—		—		0.01
— Net Income	$	0.11	$	0.03	$	0.42	$	0.24
Diluted — Net Income From Continuing Operations	$	0.10	$	0.03	$	0.41	$	0.23
— Net Income From Discontinued Operations		—		—		—		0.01
— Net Income	$	0.10	$	0.03	$	0.41	$	0.24

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. As the result of a change in membership interest that occurred on April 1, 2013, Rex Energy Corporation owns a 60% membership interest in Water Solutions and Sand Hills owns a 40% membership interest and serves as the operator of the entity. The change in ownership interests occurred in accordance with the original operating agreement which stipulated that the change would occur upon the return of our initial capital investments. The change in ownership transaction, in which we retained our

controlling financial interest, was accounted for as an equity transaction, with no impact to our Consolidated Statements of Operations. Prior to the change in membership interests, the entity was owned 80% by us and 20% by Sand Hills.

We fully consolidate the accounts of Water Solutions in our financial statements and accounted for the 40% equity interest owned by Sand Hills as a noncontrolling interest. Water Solutions is financed through cash contributions from its members and a credit facility upon which $8.1 million was drawn as of September 30, 2014. As of September 30, 2014, Water Solutions maintained capital leases of approximately $2.9 million and equipment loans of approximately $2.5 million. Capital contributions to Water Solutions during the first nine months of 2014 and 2013 were negligible. The table below sets forth the carrying amount and classifications of Water Solutions’ assets and liabilities as of September 30, 2014 and December 31, 2013, with no restrictions or obligations to use certain assets to settle associated liabilities:

We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our Appalachian Basin operations. We recorded our investment in RW Gathering of approximately $18.1 million and $18.7 million as of September 30, 2014 and December 31, 2013, respectively, on our Consolidated Balance Sheets as Equity Method Investments. We did not make any capital contributions to RW Gathering during the first nine months of 2014 as compared to contributions of $2.5 million in cash to support gathering line construction during first nine months of 2013. RW Gathering recorded net losses from continuing operations of $0.5 million and $1.5 million for each of the three and nine months ended September 30, 2014, respectively, as compared to losses of $0.5 million and $1.4 million for each of the three and nine months ended September 30, 2013, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Our share of the net loss is recorded on the Statements of Operations as Loss on Equity Method Investments.

During the three and nine-month periods ended September 30, 2014, we incurred approximately $0.2 million and $0.5 million in compression expenses for 2014, respectively, as compared to $0.3 million and $0.6 million for 2013, respectively, 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 September 30, 2014 and December 31, 2013, there were no receivables due from RW Gathering to us.

For the three and nine months ended September 30, 2014, impairment expenses incurred were negligible compared to $2.2 million and $2.4 million in impairment expenses for the three and nine months ended September 30, 2013, 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. The expense incurred as of September 30, 2013 was primarily related to acreage in our non-operated dry gas region of Clearfield County, Pennsylvania. These leases were approaching expiration and there was no existing plan to extend the leases or develop the acreage. As of September 30, 2014, we continued to carry the costs of undeveloped properties of approximately $334.5 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans.

For the three and nine months ended September 30, 2014, we incurred approximately $1.5 million and $4.9 million in exploration expenses, respectively, as compared to $3.2 million and $7.5 million in exploration expenses for the same periods ended September 30, 2013, respectively. Approximately $3.3 million of the expense incurred in 2014 was due to geological and geophysical type expenditures. An additional $1.2 million of expense was incurred through the payment of delay rentals, predominately in the Appalachian Basin. Approximately $7.0 million of the expense incurred in 2013 was due to geological and geophysical type expenditures and delay rental payments. An additional $0.5 million of expense was related to one exploratory well in Posey County, Indiana determined to be a dry hole.

As of September 30, 2014, we had $675.0 million of outstanding Senior Notes, as shown in Note 8, Long-Term Debt, to our Consolidated Financial Statements. The Senior Notes are guaranteed by certain of our wholly-owned subsidiaries, or guarantor subsidiaries. Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of September 30, 2014:

The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of September 30, 2014, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries.

The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of September 30, 2014 and December 31, 2013, the condensed consolidating statements of operations for each of the three and nine-month periods ended September 30, 2014 and 2013, and the condensed consolidating statements of cash flows for each of the nine-month periods ended September 30, 2014 and 2013.

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	87,302		$	315		$	5		$	—		$	87,622
Accounts Receivable		41,785			13,337			—			(1,729	)		53,393
Taxes Receivable		—			—			504			—			504
Short-Term Derivative Instruments		7,257			—			—			—			7,257
Current Deferred Tax Asset		—			—			2,837			—			2,837
Inventory, Prepaid Expenses and Other		2,905			297			43			—			3,245
Total Current Assets		139,249			13,949			3,389			(1,729	)		154,858
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,017,608			191			—			(5,332	)		1,012,467
Unevaluated Oil and Gas Properties		333,600			861			—			—			334,461
Other Property and Equipment		62,110			21,535			—			—			83,645
Wells and Facilities in Progress		110,046			7,228			—			(295	)		116,979
Pipelines		17,773			—			—			(1,898	)		15,875
Total Property and Equipment		1,541,137			29,815			—			(7,525	)		1,563,427
Less: Accumulated Depreciation, Depletion and Amortization		(251,704	)		(4,584	)		—			817			(255,471	)
Net Property and Equipment		1,289,433			25,231			—			(6,708	)		1,307,956
Deferred Financing Costs and Other Assets—Net		2,422			144			15,020			—			17,586
Equity Method Investments		18,098			—			—			—			18,098
Intercompany Receivables		—			—			966,226			(966,226	)		—
Investment in Subsidiaries – Net		4,161			3,438			355,797			(363,396	)		—
Long-Term Derivative Instruments		430			—			—			—			430
Total Assets	$	1,453,793		$	42,762		$	1,340,432		$	(1,338,059	)	$	1,498,928
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	56,909		$	1,391		$	—		$	(1,731	)	$	56,569
Current Maturities of Long-Term Debt		1,011			7,237			—			—			8,248
Accrued Liabilities		50,813			4,683			15,339			—			70,835
Short-Term Derivative Instruments		1,321			—			—			—			1,321
Total Current Liabilities		110,054			13,311			15,339			(1,731	)		136,973
8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
6.25% Senior Notes Due 2022		—			—			325,000			—			325,000
Premium on Senior Notes – Net		—			—			2,816			—			2,816
Senior Secured Line of Credit and Other Long-Term Debt		130			6,255			—			—			6,385
Long-Term Derivative Instruments		945			—			—			—			945
Long-Term Deferred Tax Liability		—			—			43,414			—			43,414
Other Deposits and Liabilities		4,303			—			—			—			4,303
Future Abandonment Cost		27,402			32			—			—			27,434
Intercompany Payables		962,392			3,834			—			(966,226	)		—
Total Liabilities		1,105,226			23,432			736,569			(967,957	)		897,270
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			54			—			54
Additional Paid-In Capital		177,144			82,780			616,384			(259,924	)		616,384
Accumulated Earnings (Deficit)		171,423			(64,412	)		(12,576	)		(113,518	)		(19,083	)
Rex Energy Stockholders’ Equity		348,567			18,368			603,863			(373,442	)		597,356
Noncontrolling Interests		—			962			—			3,340			4,302
Total Stockholders’ Equity		348,567			19,330			603,863			(370,102	)		601,658
Total Liabilities and Stockholders’ Equity	$	1,453,793		$	42,762		$	1,340,432		$	(1,338,059	)	$	1,498,928

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	73,343		$	105		$	—		$	—		$	73,448
Field Services Revenue		—			15,870			—			(2,800	)		13,070
Other Revenue		18			—			—			—			18
TOTAL OPERATING REVENUE		73,361			15,975			—			(2,800	)		86,536
OPERATING EXPENSES
Production and Lease Operating Expense		27,668			4			—			(15	)		27,657
General and Administrative Expense		7,709			1,160			1,555			(15	)		10,409
Loss on Disposal of Asset		175			(91	)		—			—			84
Impairment Expense		1			—			—			—			1
Exploration Expense		1,452			10			—			—			1,462
Depreciation, Depletion, Amortization and Accretion		26,536			1,027			—			(199	)		27,364
Field Services Operating Expense		—			11,464			—			(1,917	)		9,547
Other Operating (Income) Expense		(24	)		—			—			—			(24	)
TOTAL OPERATING EXPENSES		63,517			13,574			1,555			(2,146	)		76,500
INCOME (LOSS) FROM OPERATIONS		9,844			2,401			(1,555	)		(654	)		10,036
OTHER INCOME (EXPENSE)
Interest Expense		(56	)		(134	)		(10,890	)		—			(11,080	)
Gain (Loss) on Derivatives, Net		12,316			—			—			—			12,316
Other Expense		3			—			—			(15	)		(12	)
Loss From Equity Method Investments		(202	)		—			—			—			(202	)
Income (Loss) From Equity in Consolidated Subsidiaries		18			(18	)		12,840			(12,840	)		—
TOTAL OTHER INCOME (EXPENSE)		12,079			(152	)		1,950			(12,855	)		1,022
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		21,923			2,249			395			(13,509	)		11,058
Income Tax (Expense) Benefit		(8,853	)		(915	)		5,299			—			(4,469	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		13,070			1,334			5,694			(13,509	)		6,589
Net Income Attributable to Noncontrolling Interests		—			895			—			—			895
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	13,070		$	439		$	5,694		$	(13,509	)	$	5,694

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	227,547		$	103		$	—		$	—		$	227,650
Field Services Revenue		—			54,467			—			(13,005	)		41,462
Other Revenue		92			—			—			—			92
TOTAL OPERATING REVENUE		227,639			54,570			—			(13,005	)		269,204
OPERATING EXPENSES
Production and Lease Operating Expense		69,328			10			—			(35	)		69,303
General and Administrative Expense		22,811			2,982			4,296			(50	)		30,039
Loss on Disposal of Asset		469			(84	)		—			—			385
Impairment Expense		41			—			—			—			41
Exploration Expense		4,877			13			—			—			4,890
Depreciation, Depletion, Amortization and Accretion		66,812			2,671			—			(469	)		69,014
Field Services Operating Expense		—			40,246			—			(9,334	)		30,912
Other Operating Expense		3			—			—			—			3
TOTAL OPERATING EXPENSES		164,341			45,838			4,296			(9,888	)		204,587
INCOME (LOSS) FROM OPERATIONS		63,298			8,732			(4,296	)		(3,117	)		64,617
OTHER INCOME (EXPENSE)
Interest Expense		(86	)		(482	)		(25,150	)		—			(25,718	)
Gain (Loss) on Derivatives, Net		1,232			—			1,083			—			2,315
Other Income (Expense)		20			—			—			(50	)		(30	)
Loss From Equity Method Investments		(610	)		—			—			—			(610	)
Income (Loss) From Equity in Consolidated Subsidiaries		(64	)		64			39,667			(39,667	)		—
TOTAL OTHER INCOME (EXPENSE)		492			(418	)		15,600			(39,717	)		(24,043	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		63,790			8,314			11,304			(42,834	)		40,574
Income Tax (Expense) Benefit		(22,964	)		(2,967	)		11,339			—			(14,592	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		40,826			5,347			22,643			(42,834	)		25,982
Net Income Attributable to Noncontrolling Interests		—			3,340			—			—			3,340
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	40,826		$	2,007		$	22,643		$	(42,834	)	$	22,642

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	40,826		$	5,347		$	22,643		$	(42,834	)	$	25,982
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		610			—			—			—			610
Non-Cash Expenses (Income)		(203	)		233			5,116			—			5,146
Depreciation, Depletion, Amortization and Accretion		66,812			2,671			—			(469	)		69,014
Deferred Income Tax Expense (Benefit)		22,964			2,967			(11,339	)		—			14,592
(Gain) Loss on Derivatives		(1,232	)		—			(1,083	)		—			(2,315	)
Cash Settlements of Derivatives		(4,209	)		—			878			—			(3,331	)
Dry Hole Expense		237			—			—			—			237
Loss on Sale of Asset		469			(84	)		—			—			385
Impairment Expense		41			—			—			—			41
Changes in operating assets and liabilities
Accounts Receivable		(9,510	)		(3,455	)		4,685			(1,574	)		(9,854	)
Inventory, Prepaid Expenses and Other Assets		(812	)		(209	)		(17	)		—			(1,038	)
Accounts Payable and Accrued Liabilities		22,975			(1,007	)		12,518			1,574			36,060
Other Assets and Liabilities		(1,942	)		(24	)		—			—			(1,966	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		137,026			6,439			33,401			(43,303	)		133,563
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		408,192			248			(448,109	)		39,669			—
Proceeds from Joint Venture Acreage Management		210			—			—			—			210
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		248			164			—			—			412
Acquisitions of Undeveloped Acreage		(152,765	)		(863	)		—			—			(153,628	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(305,672	)		(8,315	)		—			3,634			(310,353	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(49,787	)		(8,766	)		(448,109	)		43,303			(463,359	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			22,041			171,000			—			193,041
Repayments of Long-Term Debt and Lines of Credit		—			(18,146	)		(230,000	)		—			(248,146	)
Repayments of Loans and Other Long-Term Debt		(1,323	)		(675	)		—			—			(1,998	)
Proceeds from Senior Notes, Net of Discounts and Premiums		—			—			325,000			—			325,000
Debt Issuance Costs		—			(7	)		(6,724	)		—			(6,731	)
Proceeds from the Issuance of Preferred Stock, Net		—			—			155,011			—			155,011
Proceeds from Exercise of Stock Options		—			—			421			—			421
Distributions by the Partners of Consolidated Subsidiaries		—			(1,080	)		—			—			(1,080	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,323	)		2,133			414,708			—			415,518
NET INCREASE (DECREASE) IN CASH		85,916			(194	)		—			—			85,722
CASH – BEGINNING		1,386			509			5			—			1,900
CASH - ENDING	$	87,302		$	315		$	5		$	—		$	87,622

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,386		$	509		$	5		$	—		$	1,900
Accounts Receivable		32,283			9,882			—			(3,302	)		38,863
Taxes Receivable		—			—			5,189			—			5,189
Short-Term Derivative Instruments		5,180			—			488			—			5,668
Current Deferred Tax Asset		—			—			3,451			—			3,451
Inventory, Prepaid Expenses and Other		2,092			89			26			—			2,207
Total Current Assets		40,941			10,480			9,159			(3,302	)		57,278
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		752,781			—			—			(3,101	)		749,680
Unevaluated Oil and Gas Properties		189,385			—			—			—			189,385
Other Property and Equipment		57,409			12,706			—			—			70,115
Wells and Facilities in Progress		70,759			6,576			—			(790	)		76,545
Pipelines		7,678			—			—			—			7,678
Total Property and Equipment		1,078,012			19,282			—			(3,891	)		1,093,403
Less: Accumulated Depreciation, Depletion and Amortization		(188,699	)		(2,172	)		—			350			(190,521	)
Net Property and Equipment		889,313			17,110			—			(3,541	)		902,882
Deferred Financing Costs and Other Assets—Net		2,421			206			9,366			—			11,993
Equity Method Investments		18,708			—			—			—			18,708
Intercompany Receivables		—			—			628,517			(628,517	)		—
Investment in Subsidiaries – Net		4,442			1,197			216,945			(222,584	)		—
Long-Term Derivative Instruments		535			—			—			—			535
Total Assets	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	33,613		$	794		$	—		$	(3,304	)	$	31,103
Current Maturities of Long-Term Debt		1,339			5,404			—			—			6,743
Accrued Liabilities		45,196			6,287			2,967			—			54,450
Short-Term Derivative Instruments		4,663			—			—			—			4,663
Total Current Liabilities		84,811			12,485			2,967			(3,304	)		96,959
8.875% Senior Notes Due 2020		—			—			350,000			—			350,000
Premium (Discount) on Senior Notes – Net		—			—			3,078			—			3,078
Senior Secured Line of Credit and Other Long-Term Debt		137			3,054			59,000			—			62,191
Long-Term Derivative Instruments		1,071			—			694			—			1,765
Long-Term Deferred Tax Liability		—			—			29,446			—			29,446
Other Deposits and Liabilities		4,992			—			—			—			4,992
Future Abandonment Cost		26,027			13			—			—			26,040
Intercompany Payables		554,329			74,188			—			(628,517	)		—
Total Liabilities		671,367			89,740			445,185			(631,821	)		574,471
Stockholders’ Equity
Common Stock		—			—			54			—			54
Additional Paid-In Capital		177,144			6,488			456,554			(183,632	)		456,554
Accumulated Earnings (Deficit)		107,849			(67,720	)		(37,806	)		(44,048	)		(41,725	)
Rex Energy Stockholders’ Equity		284,993			(61,232	)		418,802			(227,680	)		414,883
Noncontrolling Interests		—			485			—			1,557			2,042
Total Stockholders’ Equity		284,993			(60,747	)		418,802			(226,123	)		416,925
Total Liabilities and Stockholders’ Equity	$	956,360		$	28,993		$	863,987		$	(857,944	)	$	991,396

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	58,063		$	—		$	—		$	—		$	58,063
Field Services Revenue		—			6,543			—			(1,696	)		4,847
Other Revenue		64			—			—			—			64
TOTAL OPERATING REVENUE		58,127			6,543			—			(1,696	)		62,974
OPERATING EXPENSES
Production and Lease Operating Expense		17,201			2			—			—			17,203
General and Administrative Expense		6,863			617			1,361			(15	)		8,826
Loss on Disposal of Asset		94			46			—			—			140
Impairment Expense		2,244			—			—			—			2,244
Exploration Expense		3,241			1			—			—			3,242
Depreciation, Depletion, Amortization and Accretion		15,876			435			—			(44	)		16,267
Field Services Operating Expense		—			4,821			—			(1,169	)		3,652
Other Operating Expense		19			—			—			—			19
TOTAL OPERATING EXPENSES		45,538			5,922			1,361			(1,228	)		51,593
INCOME (LOSS) FROM OPERATIONS		12,589			621			(1,361	)		(468	)		11,381
OTHER INCOME (EXPENSE)
Interest Expense		(16	)		(26	)		(6,139	)		—			(6,181	)
Gain on Derivatives, Net		(4,624	)		—			—			—			(4,624	)
Other Income (Expense)		(15	)		—			—			(15	)		(30	)
Loss From Equity Method Investments		(207	)		—			—			—			(207	)
Income (Loss) From Equity in Consolidated Subsidiaries		(22	)		22			7,653			(7,653	)		—
TOTAL OTHER INCOME (EXPENSE)		(4,884	)		(4	)		1,514			(7,668	)		(11,042	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		7,705			617			153			(8,136	)		339
Income Tax (Expense) Benefit		11			61			1,421			—			1,493
INCOME (LOSS) FROM CONTINUING OPERATIONS		7,716			678			1,574			(8,136	)		1,832
Income From Discontinued Operations, Net of Income Taxes		—			—			—			—			—
NET INCOME (LOSS)		7,716			678			1,574			(8,136	)		1,832
Net Income Attributable to Noncontrolling Interests		—			258			—			—			258
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	7,716		$	420		$	1,574		$	(8,136	)	$	1,574

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	150,447		$	—		$	—		$	—		$	150,447
Field Services Revenue		—			19,668			—			(4,475	)		15,193
Other Revenue		164			—			—			—			164
TOTAL OPERATING REVENUE		150,611			19,668			—			(4,475	)		165,804
OPERATING EXPENSES
Production and Lease Operating Expense		43,688			7			—			—			43,695
General and Administrative Expense		18,896			1,765			3,814			(71	)		24,404
Loss on Disposal of Asset		1,586			46			—			—			1,632
Impairment Expense		2,414			—			—			—			2,414
Exploration Expense		7,510			1			—			—			7,511
Depreciation, Depletion, Amortization and Accretion		39,434			1,038			—			(105	)		40,367
Field Services Operating Expense		—			13,468			—			(3,114	)		10,354
Other Operating Expense		910			—			—			—			910
TOTAL OPERATING EXPENSES		114,438			16,325			3,814			(3,290	)		131,287
INCOME (LOSS) FROM OPERATIONS		36,173			3,343			(3,814	)		(1,185	)		34,517
OTHER INCOME (EXPENSE)
Interest Expense		(47	)		(66	)		(15,900	)		—			(16,013	)
Gain on Derivatives, Net		(1,423	)		—			—			—			(1,423	)
Other Income (Expense)		2,112			—			—			(71	)		2,041
Loss From Equity Method Investments		(569	)		—			—			—			(569	)
Income (Loss) From Equity in Consolidated Subsidiaries		(44	)		44			25,510			(25,510	)		—
TOTAL OTHER INCOME (EXPENSE)		29			(22	)		9,610			(25,581	)		(15,964	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		36,202			3,321			5,796			(26,766	)		18,553
Income Tax (Expense) Benefit		(11,546	)		(759	)		6,683			—			(5,622	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		24,656			2,562			12,479			(26,766	)		12,931
Income From Discontinued Operations, Net of Income Taxes		—			460			—			—			460
NET INCOME (LOSS)		24,656			3,022			12,479			(26,766	)		13,391
Net Income Attributable to Noncontrolling Interests		—			912			—			—			912
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	24,656		$	2,110		$	12,479		$	(26,766	)	$	12,479

($ in Thousands)	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	24,656		$	3,022		$	12,479		$	(26,766	)	$	13,391
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss From Equity Method Investments		569			—			—			—			569
Non-Cash Expenses		(180	)		65			4,547			—			4,432
Depreciation, Depletion, Amortization and Accretion		39,434			1,038			—			(105	)		40,367
Deferred Income Tax Expense (Benefit)		12,060			1,169			(2,259	)		—			10,970
Gain on Derivatives		1,423			—			—			—			1,423
Cash Settlements of Derivatives		5,540			—			—			—			5,540
Dry Hole Expense		485			—			—			—			485
(Gain) Loss on Sale of Asset		1,586			(923	)		—			—			663
Impairment Expense		2,414			—			—			—			2,414
Changes in operating assets and liabilities
Accounts Receivable		(2,628	)		(669	)		—			(3,731	)		(7,028	)
Inventory, Prepaid Expenses and Other Assets		(316	)		(66	)		(9	)		—			(391	)
Accounts Payable and Accrued Liabilities		23,174			(1,687	)		9,241			4,022			34,750
Other Assets and Liabilities		(1,495	)		(88	)		(247	)		—			(1,830	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		106,722			1,861			23,752			(26,580	)		105,755
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		139,294			688			(165,201	)		25,219			—
Proceeds from Joint Venture Acreage Management		246			—			—			—			246
Contributions to Equity Method Investments		(2,493	)		—			—			—			(2,493	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		697			3,234			—			—			3,931
Acquisitions of Undeveloped Acreage		(31,456	)		(2	)		—			—			(31,458	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(193,964	)		(4,661	)		—			1,361			(197,264	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(87,676	)		(741	)		(165,201	)		26,580			(227,038	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			1,750			—			—			1,750
Repayments of Long-Term Debt and Lines of Credit		—			(1,022	)		—			—			(1,022	)
Repayments of Loans and Other Notes Payable		(934	)		(429	)		—			—			(1,363	)
Proceeds from Senior Notes, net of Discounts and Premiums		—			—			105,000			—			105,000
Debt Issuance Costs		—			—			(3,004	)		—			(3,004	)
Proceeds from the Exercise of Stock Options		—			—			534			—			534
Purchase of Non-Controlling Interests		—			(150	)		—			—			(150	)
Distributions by the Partners of Consolidated Subsidiaries		—			(646	)		—			—			(646	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(934	)		(497	)		102,530			—			101,099
NET INCREASE (DECREASE) IN CASH		18,112			623			(38,919	)		—			(20,184	)
CASH – BEGINNING		4,227			824			38,924			—			43,975
CASH - ENDING	$	22,339		$	1,447		$	5		$	—		$	23,791

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended December 31, 2013 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

We use a variety of financial and operational measurements at interim periods to analyze our performance. These measurements include an analysis of production and sales revenue for the period; EBITDAX, a non-GAAP financial measurement; lease operating expenses per Mcf equivalent (“LOE per Mcfe”); and general and administrative (“G&A”) expenses per Mcfe.

We are an independent oil and gas company operating in the Appalachian Basin and Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and 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 exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. In addition to our drilling and exploration activities, we are also engaged in oil and gas field services, where we provide water sourcing, water disposal and water transfer solutions for completion operations.

We divide our operations into two principal business segments: (1) exploration and production and (2) field services. We are headquartered in State College, Pennsylvania, and have regional offices in Bridgeport, Illinois; Cranberry, Pennsylvania; and Carrolton, Ohio.

During the three and nine months ended September 30, 2014, we produced 14,327 MMcfe and 34,699 MMcfe, respectively, in the Appalachian Basin. In the Illinois Basin, we produced 214 MBbls and 604 MBbls during the three and nine months ended September 30, 2014, respectively. Overall, our production for the three and nine months ended September 30, 2014 averaged 169,658 Mcfe per day and 140,385 Mcfe per day, respectively. As of September 30, 2014, we had 13.0 gross (9.4 net) wells drilled and awaiting completion and five gross (3.5 net) wells resting and awaiting pipeline connection. Our drilling and completion activity for the period indicated in each of our regions is set forth in the tables below.

On July 14, 2014, we issued $325.0 in million aggregate principal amount of 6.25% senior notes in an offering at an issue price of 100.0% of the aggregate principal amount of senior notes, due to mature on August 1, 2022. We received net proceeds in the offering of approximately $318.8 million, after discounts and offering expenses. Interest is payable semi-annually at a rate of 6.25% per annum on February 1 and August 1 of each year, with the first interest payment to be made on February 1, 2015. We used the proceeds of the offering to repay all of the borrowings outstanding under our Senior Credit Facility, which was $218.0 million at the time of the payment, and expect to use the remaining proceeds for general corporate purposes.

On September 9, 2014, we completed the acquisition of approximately 208,000 gross (207,000 net) acres prospective for the Marcellus, Upper Devonian/Burkett and Utica Shales from SWEPI, LP, an affiliate of Royal Dutch Shell, plc (“Shell”) for approximately $120.6 million in cash, after customary closing adjustments. Included in the acquisition were several producing wells and properties in various stages of development. The assets acquired are located in Armstrong, Beaver, Butler, Lawrence, Mercer and Venango counties in Pennsylvania and Columbiana and Mahoning counties in Ohio.

The following table sets forth summary information regarding oil, NGL and natural gas production and product prices for the three and nine months ended September 30, 2014 and 2013.

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2014		2013		2014		2013
Production:
Oil and Condensate (Bbls)		306,088		252,426		808,357		664,257
Natural Gas (Mcf)		9,846,693		6,169,918		25,681,687		16,413,517
C3+ NGLs (Bbls)		411,655		233,350		1,042,378		549,559
Ethane (Bbls)		242,557		—		256,505		—
Total (Mcfe)(a)		15,608,493		9,084,574		38,325,127		23,696,413
Average daily production:
Oil and Condensate (Bbls)		3,327		2,744		2,961		2,433
Natural Gas (Mcf)		107,029		67,064		94,072		60,123
C3+ NGLs (Bbls)		4,475		2,536		3,818		2,013
Ethane (Bbls)		2,636		—		940		—
Total (Mcfe)(a)		169,658		98,745		140,385		86,799
Average sales price(b):
Oil and Condensate (per Bbl)	$	90.00	$	102.38	$	93.28	$	95.79
Natural Gas (per Mcf)	$	2.53	$	3.47	$	3.79	$	3.76
C3+ NGLs (per Bbl)	$	46.49	$	46.25	$	50.74	$	45.63
Ethane (per Bbl)	$	7.76	$	-	$	7.67	$	-
Total (per Mcfe)(a)	$	4.71	$	6.39	$	5.94	$	6.35
Average NYMEX prices(c):
Oil (per Bbl)	$	97.17	$	105.94	$	99.61	$	98.17
Natural Gas (per Mcf)	$	3.97	$	3.56	$	4.43	$	3.68

The following table sets forth summary information by basin regarding oil, NGL and natural gas revenues, production volumes, average product prices and average production costs for the three and nine months ended September 30, 2014 and 2013.

	Production and Revenue by Basin
	For Three Months Ended September 30,				For Nine Months Ended September 30,
	2014		2013		2014		2013
Appalachian
Revenue – Natural Gas(a)	$	24,882,893	$	21,426,517	$	97,381,007	$	61,741,634
Volumes (Mcf)		9,846,693		6,169,918		25,681,687		16,413,517
Average Price	$	2.53	$	3.47	$	3.79	$	3.76
Revenue – Condensate (a)	$	7,402,341	$	5,239,202	$	17,108,064	$	7,768,178
Volumes (Bbl)		92,457		54,978		203,961		84,292
Average Price	$	80.06	$	95.30	$	83.88	$	92.16
Revenue – C3+ NGLs(a)	$	19,135,861	$	10,793,295	$	52,895,161	$	25,076,069
Volumes (Bbl)		411,655		233,350		1,042,378		549,559
Average Price	$	46.49	$	46.25	$	50.74	$	45.63
Revenue – Ethane(a)	$	1,882,916	$	—	$	1,966,642	$	—
Volumes (Bbl)		242,557		—		256,505		—
Average Price	$	7.76	$	—	$	7.67	$	—
Average Production Cost per Mcfe(b)	$	1.33	$	1.32	$	1.28	$	1.23
Illinois
Revenue – Oil(a)	$	20,144,217	$	20,604,040	$	58,299,255	$	55,861,052
Volumes (Bbl)		213,632		197,448		604,396		579,965
Average Price	$	94.29	$	104.35	$	96.46	$	96.32
Average Production Cost per Bbl(b)	$	38.81	$	32.86	$	38.87	$	31.47

Operating revenue for the three and nine months ended September 30, 2014 increased 37.4% and 62.4%, respectively, when compared to the same periods in 2013. The increase in operating revenue for the three and nine-month periods ended September 30, 2014, can be primarily attributed to higher production in both of our operating regions and increased revenues from our field services segment, partially offset by lower commodity prices, particularly natural gas and oil during the quarter and natural gas during the nine-month period. In the Appalachian Basin, our production grew to 14,327 MMcfe for the three-month period ended September 30, 2014, from 7,900 MMcfe for the three-month period ended September 30, 2013, or approximately 81.4%, while production in the Illinois Basin increased to 214 MBbls during the quarter ended September 30, 2014, from 197 MBbls during the same period in 2013, or approximately 8.2%. For the nine months ended September 30, 2014, production in the Appalachian Basin has increased 71.6% to 34,699 MMcfe from the same period in 2013, while production in the Illinois Basin for the nine months ended September 30, 2014 increased 4.2% to 604 MBls from the same period in 2013. For the three-month period ended September 30, 2014, our realized sales price for oil, natural gas and NGLs, decreased by $12.38 per bbl, $0.94 per mcf and $14.13 per barrel, respectively, when compared to the same period in 2013. For the nine-month period ended September 30, 2014, our realized sales price for oil and NGLs, decreased by $2.51 per bbl and $3.39 per bbl, respectively, when compared to the same period in 2013. Also contributing to our increased revenue was the continued growth of our field services segment from $4.8 million in revenue for the quarter ended September 30, 2013 to $13.1 million in revenue for the quarter ended September 30, 2014, and from $15.2 million for the nine months ended September 30, 2013 to $41.5 million during the nine months ended September 30, 2014. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays have led to the growth of our field services activities, particularly water pipeline and water transfer to service well completion activities.

For the nine months ended September 30, 2014, we spent approximately $464.0 million on drilling projects, facilities and related equipment, undeveloped acreage and asset acquisitions, including the Shell acquisition. Approximately 90.0% of our capital expenditures in 2014 have been in the Appalachian Basin and approximately 10% of our capital expenditures have been in the Illinois Basin.

Operating expenses increased $24.9 million and $73.3 million for the three and nine-month periods ended September 30, 2014, respectively, as compared to the same periods in 2013. Operating expenses primarily comprise: Production and Lease Operating Expenses, G&A Expenses, Gain/Loss on Disposal of Assets, Exploration Expenses, Impairment Expense, DD&A Expenses and Field Operating Expenses. The increases in operating expenses were largely attributable to Production and Lease Operating Expense, G&A Expense, DD&A and Field Service Operating Expense. The growth of these operating expenses is consistent with our overall organizational growth as we continue to increase our drilling and exploration activity and our number of revenue generating assets.

Comparison of the Three Months Ended September 30, 2014 to the Three Months Ended September 30, 2013

Oil, NGL and gas revenue, including the effects of cash settled derivatives, for the three-month periods ended September 30, 2014 and 2013 is summarized in the following table:

	For Three Months Ended September 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2014			2013			Change			%
Oil and Gas Revenue:
Oil and condensate sales revenue	$	27,547		$	25,843		$	1,704			6.6	%
Oil derivatives realized(a)	$	(194	)	$	(2,404	)	$	2,210			-91.9	%
Total oil and condensate revenue and derivatives realized	$	27,353		$	23,439		$	3,914			16.7	%
Gas sales revenue	$	24,883		$	21,427		$	3,456			16.1	%
Gas derivatives realized(a)	$	2,798		$	3,227		$	(429	)		-13.3	%
Total gas revenue and derivatives realized	$	27,681		$	24,654		$	3,027			12.3	%
C3+ NGL revenue	$	19,136		$	10,793		$	8,343			77.3	%
C3+ NGL derivatives realized(a)	$	399		$	(82	)	$	481			-586.6	%
Total C3+ NGL revenue	$	19,535		$	10,711		$	8,824			82.4	%
Ethane revenue	$	1,883		$	—		$	1,883			100.0	%
Ethane derivatives realized(a)	$	—		$	—		$	—			0.0	%
Total Ethane revenue	$	1,883		$	—		$	1,883			100.0	%
Consolidated sales	$	73,449		$	58,063		$	15,386			26.5	%
Consolidated derivatives realized(a)	$	3,003		$	741		$	2,262			305.3	%
Total oil, NGL and gas revenue and derivatives realized	$	76,452		$	58,804		$	17,648			30.0	%
Total Mcfe Production		15,608,493			9,084,574			6,523,919			71.8	%
Average Realized Price per Mcfe	$	4.90		$	6.47		$	(1.57	)		-24.3	%

Average realized price received for oil, NGLs and natural gas during the third quarter of 2014, after the effect of derivative activities, was $4.90 per Mcfe, a decrease of 24.3%, or $1.57 per Mcfe, from the same period in 2013. This decrease was primarily due to a decrease in all commodity prices during the quarter which was partially offset by positive cash settlements on derivatives. The average price for natural gas, after the effect of derivative activities, decreased 29.6%, or $1.18 per Mcf, to $2.81 per Mcf. The average price for oil and condensate, after the effect of derivative activities, decreased 3.8%, or $3.49 per barrel, to $89.36 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, increased 3.4%, or $1.55 per barrel, to $47.45 per barrel. During the second quarter of 2014, we commenced sales of ethane, which had previously been separated from our NGL stream and primarily burned as fuel with small amounts blended with our C3+ NGL sales. The average price for ethane during the three months ended September 30, 2014 was approximately $7.76 per barrel. Our derivative activities effectively increased net realized prices by $0.19 per Mcfe in the third quarter of 2014 and effectively increased net realized prices by $0.08 per Mcfe in the third quarter of 2013.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $1.44 per mcf during the third quarter of 2014 primarily due to basis differentials in the northeastern United States. We have been able to lessen the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. We have basis swaps in place for 1,500 MMcf at an average differential to Henry Hub NYMEX of $0.37 per mcf for the remainder of 2014 in addition to basis swaps for 1,200 MMcf at an average differential to Henry Hub NYMEX of $0.56 for 2015. During the third quarter of 2014, we received cash settlements of approximately $1.9 million related to our basis swaps. In addition, we have been targeting sales points outside of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast.

During the second quarter 2014, we entered two separate transportation agreements. The first transportation agreement, which begins in late 2016 and has a term of 20 years, allows for the firm transportation of 130,000 MMbtu per day of natural gas from our Butler County, Pennsylvania operated area to the Lebanon Interconnect in Warren County, Ohio. The second transportation agreement, which begins in 2016 and has a term of 20 years, allows for the firm transportation of 100,000 MMbtu per day, increasing to 130,000 MMbtu per day in 2017, from the Lebanon Interconnect in Warren County, Ohio to the Gulf South Bosco Meter in Louisiana.

Production volumes in the third quarter of 2014 increased 71.8% from the third quarter of 2013. Natural gas production increased approximately 59.6%, oil and condensate production increased approximately 21.3% and our NGL production increased approximately 180.4%. Our production continues to be positively impacted by strong drilling results in the Appalachian Basin.

Overall, our production for the three months ended September 30, 2014 averaged 169,658 Mcfe per day, of which 63.1% was attributable to natural gas, 11.8% to oil and condensate, 15.8% to C3+ NGLs and 9.3% was a result of ethane production.

Statements of Operations for the three-month periods ended September 30, 2014 and 2013 are as follows:

	For the Three Months Ended September 30,
($ in Thousands)	2014			2013			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	73,448		$	58,063		$	15,385			26.5	%
Field Services Revenue		13,070			4,847			8,223			169.7	%
Other Revenue		18			64			(46	)		(71.9	)%
TOTAL OPERATING REVENUE		86,536			62,974			23,562			37.4	%
OPERATING EXPENSES
Production and Lease Operating Expense		27,657			17,203			10,454			60.8	%
General and Administrative Expense		10,409			8,826			1,583			17.9	%
Loss on Disposal of Asset		84			140			(56	)		(40.0	)%
Impairment Expense		1			2,244			(2,243	)		(100.0	)%
Exploration Expense		1,462			3,242			(1,780	)		(54.9	)%
Depreciation, Depletion, Amortization and Accretion		27,364			16,267			11,097			68.2	%
Field Service Operating Expense		9,547			3,652			5,895			161.4	%
Other Operating Expense (Income)		(24	)		19			(43	)		(226.3	)%
TOTAL OPERATING EXPENSES		76,500			51,593			24,907			48.3	%
INCOME FROM OPERATIONS		10,036			11,381			(1,345	)		(11.8	)%
OTHER EXPENSE
Interest Expense		(11,080	)		(6,181	)		(4,899	)		79.3	%
Gain (Loss) on Derivatives, Net		12,316			(4,624	)		16,940			(366.3	)%
Other Expense		(12	)		(30	)		18			(60.0	)%
Loss on Equity Method Investments		(202	)		(207	)		5			(2.4	)%
TOTAL OTHER INCOME (EXPENSE)		1,022			(11,042	)		12,064			(109.3	)%
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX		11,058			339			10,719			3,161.9	%
Income Tax (Expense) Benefit		(4,469	)		1,493			(5,962	)		(399.3	)%
INCOME FROM CONTINUING OPERATIONS		6,589			1,832			4,757			259.7	%
Income From Discontinued Operations, Net of Income Taxes		—			—			-			0.0	%
NET INCOME		6,589			1,832			4,757			259.7	%
Net Income Attributable to Noncontrolling Interests		895			258			637			246.9	%
NET INCOME ATTRIBUTABLE TO REX ENERGY	$	5,694		$	1,574		$	4,120			261.8	%

Field Services Revenue for the three months ended September 30, 2014 increased approximately $8.2 million, as compared to the third quarter of 2013. We generate field services revenue from various field service activities such as the management of water sourcing, water transfer and water disposal activities in the Appalachian Basin. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays have led to the growth of our field services activities, particularly water pipeline construction and water transfer to service well completion activities.

Production and Lease Operating Expense increased approximately $10.5 million, or 60.8%, in the third quarter of 2014 from the same period in 2013. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells in the Appalachian Basin and related production as they relate to variable type costs such as transportation, marketing, processing and gathering. For the third quarter of 2014, transportation, capacity and processing fees accounted for approximately 56.7% of our total Production and Lease Operating Expense as compared to 44.3% in the third quarter of 2013. These types of agreements typically have a term of several years, and we expect fees associated with these agreements to continue to comprise a significant portion of our Production and Lease Operating Expense.

G&A Expense for the third quarter of 2014 increased approximately $1.6 million, or 17.9%, to $10.4 million from the same period in 2013. The year-over-year increase is predominately due to the expansion of our Appalachian Basin operations and our corporate headquarters that is commensurate with our overall organizational growth.

Exploration Expense for the three months ended September 30, 2014 was approximately $1.5 million, as compared to $3.2 million for the three months ended September 30, 2013. Approximately $0.9 million of the expense incurred in 2014 was due to geological and geophysical type expenditures. An additional $0.4 million of expense was incurred through the payment of delay rentals, predominately in the Appalachian Basin. Approximately $2.4 million of the expense incurred in 2013 was due to geological and geophysical type expenditures and delay rentals in the Appalachian Basin and $0.8 million was due to geological and geophysical type expenditures and dry hole expense in the Illinois Basin.

DD&A expenses for the three months ended September 30, 2014 increased approximately $11.1 million, or 68.2%, from $16.3 million for the same period in 2013. The period-over-period increase in DD&A expense is consistent with the growth in our asset base, reserves and production since the comparable period of 2013.

Field Service Operating Expense for the three months ended September 30, 2014 totaled approximately $9.5 million, as compared to $3.7 million for the same period 2013. 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 pipeline construction and water transfer for well completion operations.

Interest Expense for the three months ended September 30, 2014 was approximately $11.1 million as compared to $6.2 million during the third quarter of 2013. The increase in interest expense is primarily due to the issuance of our Senior Notes due 2022 in July 2014 as well as the outstanding balance on our Senior Credit Facility for a portion of the quarter prior to it being paid in full. The average balance of our outstanding debt during the third quarter of 2014 was approximately $689.1 million as compared to approximately $355.3 million for the same period in 2013.

Gain (Loss) on Derivatives, net included a gain of approximately $12.3 million for the third quarter of 2014 as compared to a loss of $4.6 million for the same period in 2013. Changes were attributable to the volatility of oil, NGL and natural gas commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher oil, NGL and natural gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil, NGL and gas production volumes given the highly volatile oil, NGL and gas commodities market.

Income Tax (Expense) Benefit was approximately $4.5 million of expense for the three months ended September 30, 2014, as compared to a $1.5 million benefit for the three months ended September 30, 2013. Our effective tax rate during the three months ended September 30, 2014, was approximately 44.0%, as compared to 1,843.2% during the comparable period in 2013. Our effective tax rate in the third quarter of 2014 was different than the statutory rate of 35% due primarily to state taxes and permanent items, including Section 162(m) limitations. The effective tax rate for the third quarter of 2013 was different than that statutory rate of 35% primarily due to changes in estimates of current and deferred state taxes identified when completing the state tax returns in 2013.

Net Income Attributable to Rex Energy for the third quarter of 2014 was approximately $5.7 million, as compared $1.6 million for the comparable period in 2013 as a result of the factors discussed above.

Comparison of the Nine Months Ended September 30, 2014 to the Nine Months Ended September 30, 2013

Oil, NGL and gas revenue, including the effects of cash settled derivatives, for the nine-month periods ended September 30, 2014 and 2013 is summarized in the following table:

	For Nine Months Ended September 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2014			2013			Change			%
Oil and Gas Revenue:
Oil and condensate sales revenue	$	75,407		$	63,629		$	11,778			18.5	%
Oil derivatives realized(a)	$	(1,622	)	$	(2,737	)	$	1,115			-40.7	%
Total oil and condensate revenue and derivatives realized	$	73,785		$	60,892		$	12,893			21.2	%
Gas sales revenue	$	97,381		$	61,742		$	35,639			57.7	%
Gas derivatives realized(a)	$	(1,544	)	$	7,831		$	(9,375	)		-119.7	%
Total gas revenue and derivatives realized	$	95,837		$	69,573		$	26,264			37.8	%
C3+ NGL revenue	$	52,895		$	25,076		$	27,819			110.9	%
C3+ NGL derivatives realized(a)	$	(1,044	)	$	446		$	(1,490	)		-334.1	%
Total C3+ NGL revenue	$	51,851		$	25,522		$	26,329			103.2	%
Ethane revenue	$	1,967		$	—		$	1,967			100.0	%
Ethane derivatives realized(a)	$	—		$	—		$	—			0.0	%
Total Ethane revenue	$	1,967		$	—		$	1,967			100.0	%
Consolidated sales	$	227,650		$	150,447		$	77,203			51.3	%
Consolidated derivatives realized(a)	$	(4,210	)	$	5,540		$	(9,750	)		-176.0	%
Total oil, NGL and gas revenue and derivatives realized	$	223,440		$	155,987		$	67,453			43.2	%
Total Mcfe Production		38,325,127			23,696,413			14,628,714			61.7	%
Average Realized Price per Mcfe	$	5.83		$	6.58		$	(0.75	)		-11.4	%

Average realized price received for oil, NGLs and natural gas during the first nine months of 2014, after the effect of derivative activities, was $5.83 per Mcfe, a decrease of 11.4%, or $0.75 per Mcfe, from the same period in 2013. This decrease was primarily due to net losses on the settlement of derivatives and lower average sales prices for oil and natural gas. The average price for natural gas, after the effect of derivative activities, decreased 12.0%, or $0.51 per Mcf, to $3.73 per Mcf. The average price for oil and condensate, after the effect of derivative activities, decreased 0.4%, or $0.39 per barrel, to $91.28 per barrel. The average price for

C3+ NGLs, after the effect of derivative activities, increased 7.1%, or $3.30 per barrel, to $49.74 per barrel. During the third quarter of 2014 we commenced sales of ethane, which had previously been separated from our NGL stream and primarily burned as fuel with small amounts blended with our C3+ NGL sales. The average price for ethane during the three months ended September 30, 2014 was approximately $7.67 per barrel. Our derivative activities effectively decreased net realized prices by $0.11 per Mcfe in the first nine months of 2014 and effectively increased net realized prices by $0.23 per Mcfe in the first nine months of 2013.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $0.64 per mcf during the nine months of 2014 primarily due to basis differentials in the northeastern United States. We have been able to lessen the impact of basis differentials to an extent by utilizing basis swaps in our derivative program. We have basis swaps in place for 1,500 MMcf at an average differential to Henry Hub NYMEX of $0.37 per mcf for the remainder of 2014 in addition to basis swaps for 1,200 MMcf at an average differential to Henry Hub NYMEX of $0.56 for 2015. During the first nine months of 2014, we received cash settlements of approximately $2.9 million related to our basis swaps. In addition, we have been targeting sales points outside of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast.

Production volumes in the first nine months of 2014 increased 61.7% from the same period in 2013. Natural gas production increased approximately 21.7%, oil and condensate production increased approximately 56.5% and our NGL production increased approximately 136.4%. Our production continues to be positively impacted by strong drilling results in the Appalachian Basin.

Overall, our production for the nine months ended September 30, 2014 averaged 140,385 Mcfe per day, of which 67.0% was attributable to natural gas, 12.7% to oil, 16.3% to C3+ NGLs and 4.0% was a result of ethane production.

Statements of Operations for the nine-month periods ended September 30, 2014 and 2013 are as follows:

	For the Nine Months Ended September 30,
($ in Thousands)	2014			2013			Change			%
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	227,650		$	150,447		$	77,203			51.3	%
Field Services Revenue		41,462			15,193			26,269			172.9	%
Other Revenue		92			164			(72	)		(43.9	)%
TOTAL OPERATING REVENUE		269,204			165,804			103,400			62.4	%
OPERATING EXPENSES
Production and Lease Operating Expense		69,303			43,695			25,608			58.6	%
General and Administrative Expense		30,039			24,404			5,635			23.1	%
Loss on Disposal of Asset		385			1,632			(1,247	)		(76.4	)%
Impairment Expense		41			2,414			(2,373	)		(98.3	)%
Exploration Expense		4,890			7,511			(2,621	)		(34.9	)%
Depreciation, Depletion, Amortization and Accretion		69,014			40,367			28,647			71.0	%
Field Service Operating Expense		30,912			10,354			20,558			198.6	%
Other Operating Expense		3			910			(907	)		(99.7	)%
TOTAL OPERATING EXPENSES		204,587			131,287			73,300			55.8	%
INCOME FROM OPERATIONS		64,617			34,517			30,100			87.2	%
OTHER EXPENSE
Interest Expense		(25,718	)		(16,013	)		(9,705	)		60.6	%
Gain (Loss) on Derivatives, Net		2,315			(1,423	)		3,738			(262.7	)%
Other Income (Expense)		(30	)		2,041			(2,071	)		(101.5	)%
Loss on Equity Method Investments		(610	)		(569	)		(41	)		7.2	%
TOTAL OTHER EXPENSE		(24,043	)		(15,964	)		(8,079	)		50.6	%
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX		40,574			18,553			22,021			118.7	%
Income Tax Expense		(14,592	)		(5,622	)		(8,970	)		159.6	%
INCOME FROM CONTINUING OPERATIONS		25,982			12,931			13,051			100.9	%
Income From Discontinued Operations, Net of Income Taxes		—			460			(460	)		(100.0	)%
NET INCOME		25,982			13,391			12,591			94.0	%
Net Income Attributable to Noncontrolling Interests		3,340			912			2,428			266.2	%
NET INCOME ATTRIBUTABLE TO REX ENERGY	$	22,642		$	12,479		$	10,163			81.4	%

Field Services Revenue for the nine months ended September 30, 2014 increased approximately $26.3 million, as compared to the first nine months of 2013. We generate field services revenue from various field service activities such as the management of water sourcing, water transfer and water disposal activities in the Appalachian Basin. Increased activity and demand in the Appalachian Basin surrounding the Marcellus and Utica Shale plays have led to the growth of our field services activities, particularly water pipeline construction and water transfer to service well completion activities.

Production and Lease Operating Expense increased approximately $25.6 million, or 58.6%, in the first nine months of 2014 from the same period in 2013. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells in the Appalachian Basin and related production as they relate to variable type costs such as transportation, marketing, processing and gathering. For the nine months ended September 30, 2014, transportation, capacity and processing fees accounted for approximately 52.1% of our total Production and Lease Operating Expense as compared to 40.3% in the first nine months of 2013. These types of agreements typically have a term of several years, and we expect fees associated with these agreements to continue to comprise a significant portion of our Production and Lease Operating Expense.

G&A Expense for the first nine months of 2014 increased approximately $5.6 million, or 23.1%, to $30.0 million from the same period in 2013. The year-over-year increase is predominately due to the expansion of our Appalachian Basin operations and our corporate headquarters that is commensurate with our overall organizational growth.

Exploration Expense for the nine months ended September 30, 2014 was approximately $4.9 million, as compared to $7.5 million for the same period in 2013. Approximately $3.3 million of the expense incurred in 2014 was due to geological and geophysical type expenditures while an additional $1.2 million was incurred through the payment of delay rentals. Approximately $5.1 million of the expense incurred in 2013 was due to geological and geophysical type expenditures and delay rentals in the Appalachian Basin and $2.4 million was due to geological and geophysical type expenditures and dry hole expense in the Illinois Basin.

DD&A expenses for the nine months ended September 30, 2014 increased approximately $28.6 million, or 71.0%, from $40.4 million for the same period in 2013. The period-over-period increase in DD&A expense is consistent with the growth in our asset base, reserves and production since the comparable period of 2013.

Field Service Operating Expense for the nine months ended September 30, 2014 totaled approximately $30.9 million, as compared to $10.4 million for the same period 2013. 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 pipeline construction and water transfer for well completion operations. As compared to the first nine months of 2013, we have experienced declining gross margins in our field services business primarily due to the diversification of our business, which has included new lower margin service offerings such as pipeline construction and water hauling.

Interest Expense for the nine months ended September 30, 2014 was approximately $25.7 million, as compared to $16.0 million during the first nine months of 2013. The increase in interest expense was due to average outstanding balance of our Senior Notes and the increase in the outstanding balance of our Senior Credit Facility in 2014. For the nine-month period ended September 30, 2014, our average outstanding debt balance was approximately $567.0 million, as compared to approximately $321.0 million for the same period in 2013.

Gain (Loss) on Derivatives, net included a gain of approximately $2.3 million for the first nine months of 2014 as compared to a loss of $1.4 million for the same period in 2013. Changes were attributable to the volatility of oil, NGL and natural gas commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher oil, NGL and natural gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil, NGL and gas production volumes given the highly volatile oil, NGL and gas commodities market.

Income Tax Expense was approximately $14.6 million for the nine months ended September 30, 2014 as compared to $5.6 million for the nine months ended September 30, 2013. Our effective tax rate for the nine-month period ended September 30, 2014, was approximately 39.2%, which was different than the statutory rate of 35% primarily due to state taxes and permanent items, including Section 162(m) limitations. Our effective tax rate for the nine-month period ended September 30, 2013, was approximately 31.9%, which was different than the statutory rate of 35% primarily due to changes in estimates of current and deferred state taxes identified when completing the state tax returns in 2013.

Net Income Attributable to Rex Energy for the first nine months of 2014 was approximately $22.6 million, as compared to $12.5 million for the comparable period in 2013, as a result of the factors discussed above.

EBITDAX (Non-GAAP) from continuing operations increased approximately $7.3 million to $42.2 million for the three-month period ended September 30, 2014, as compared to the same period in 2013. EBITDAX from continuing operations increased approximately $41.1 million to $135.3 million for the nine-month period ended September 30, 2014, as compared to the same period in 2013. The increase in EBITDAX can be primarily attributed to higher production. These increases were partially offset by decreases in commodity prices and increases in operating expenses. See “Non-GAAP Financial Measures” for our reconciliation of EBITDAX to net income.

LOE per Mcfe measures the average cost of extracting oil, NGLs and natural gas from our basin reserves during the period. This measurement is also commonly referred to in the industry as our “lifting cost”. It represents the average cost of extracting one Mcf of natural gas equivalent from our oil, NGL and natural gas reserves in the ground. LOE per Mcfe decreased to $1.77 for the three months ended September 30, 2014 as compared to $1.89 for the same period in 2013. LOE per Mcfe decreased to $1.81 for the nine months ended September 30, 2014 as compared to $1.84 for the same period in 2013. Our LOE is largely comprised of variable type costs such as transportation, marketing, processing and gathering. For the first nine months of 2014, transportation, capacity and processing fees accounted for approximately 52.1% of our total Production and Lease Operating Expense as compared to 40.3% in the first nine months of 2013. These agreements typically have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. Various agreements that we have entered include firm capacity rights, for which we may incur a fee for unused capacity. As we continue to grow our operations, particularly those in the Appalachian Basin, which have lower operating costs, we expect our lifting cost to decrease as we gain additional efficiencies of scale and utilize all of our firm capacity and transportation commitments.

Our G&A 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 G&A expenses in relation to our production because these expenses have a direct impact on our profitability. G&A expenses per Mcfe decreased to approximately $0.67 for the three-month period ended September 30, 2014, as compared to $0.97 for the same period in 2013. G&A expenses per Mcfe decreased to approximately $0.78 for the nine-month period ended September 30, 2014, as compared to $1.03 for the same period in 2013. The year-over-year decrease is predominately due to our production growth, particularly in the Appalachian Basin, which was partially offset by an increase in expenses that is commensurate with our overall organizational growth.

Our primary needs for cash are for the exploration, development and acquisition of oil and gas properties. During the nine months ended September 30, 2014, we spent $464.0 million of capital on asset acquisitions, drilling projects, facilities and related equipment and acquisitions of unproved acreage. We funded our capital program with the proceeds from an offering of Senior Notes due 2022 and preferred stock, net cash flows from operations and net proceeds from our Senior Credit Facility. The remainder of our 2014 capital budget of $71.8 million to $86.8 million is expected to be funded primarily by cash on hand, cash flow from operations and borrowings under our Senior Credit Facility, of which approximately $400.0 million was available at September 30, 2014. The amounts remaining under our original 2014 capital budget do not contemplate expenditures related to capital interest, asset acquisitions or acquisitions of unproved acreage. We currently believe 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 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 or sell non-core assets to fund capital expenditures, acquisitions, extend maturities or to repay debt.

Our ability to fund our capital expenditure program is dependent upon the level of commodity prices and the success of our exploration programs in replacing our existing oil, NGL and gas reserves. If commodity prices decrease, our operating cash flows may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of commodity prices on cash flows can be mitigated through the use of commodity derivatives. If we are unable to replace our oil, NGL and gas reserves through our acquisitions, development and exploration programs, we may also suffer a reduction in our operating cash flows and access to funds under the Senior Credit Facility. Under extreme circumstances, commodity 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 flows from operations are driven by commodity prices and production volumes. Prices for oil, NGLs 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. Historically, cash flows from operations, borrowings from our Senior Credit Facility and net proceeds from debt and equity offerings have been primarily used to fund exploration and development of our oil and gas interests.

We are not restricted as to our borrowings under the Senior Credit Facility; however we are subject to the minimum financial requirements detailed in Note 8, Long-Term Debt, to our Consolidated Financial Statements.

In connection with certain marketing, transportation and processing agreements that we have entered into, we may be obligated to pay fees in connection with these agreements of $146.8 million over the next five years, depending on our levels of production. Also in connection with certain of these agreements, we have guaranteed the payment of obligations up to a maximum of $418.2 million over the life of the agreements.

Financial Condition and Cash Flows for the Nine Months Ended September 30, 2014 and 2013

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

Net cash provided by operating activities increased by approximately $27.8 million in the first nine months of 2014 over the same period in 2013. Strong production and growth of our field services segment during the first nine months of 2014 resulted in increased cash flows from operations, which were offset by a reduction in natural gas prices and increases in lease operating expenses, G&A expenses and field service operating expenses.

Net cash used in investing activities increased by approximately $236.3 million from the first nine months of 2013 to $463.4 million in the first nine months of 2014. This change is primarily attributed to increased drilling and completion activity in 2014 in addition to our acquisition of assets in the Appalachian Basin for approximately $120.5 million in September 2014.

Net cash provided by financing activities increased by approximately $314.4 million for the first nine months of 2014 to $415.5 million from $101.1 million for the first nine months of 2013. The increase is primarily due to our issuance of Senior Notes due 2022 and preferred stock during 2014. We received net proceeds from these offerings of approximately $473.8 million. In addition to our offerings, we had net borrowings under our Senior Credit Facility of approximately $55.1 million. During the first nine months of 2013, we received net proceeds of approximately $102.0 million from an offering of Senior Notes due 2020.

Our results of operations and cash flows are affected by changing oil, NGL and natural gas prices. If the price of oil, NGLs and natural gas increases or decreases, there could be a corresponding increase or decrease in the operating cost that we are required to bear for operations, as well as an increase or decrease in revenues.

During the quarter ended September 30, 2014, there were no material changes to the critical accounting policies previously reported by us in our Annual Report on Form 10-K for the year ended December 31, 2013. We describe critical recently adopted and issued accounting standards in Part I, Item 1. Financial Statements—Note 6, “Recently Issued Accounting Pronouncements.”

“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, DD&A, unrealized losses from financial derivatives, exploration expenses and other similar 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 its financial statements, such as our commercial bank lenders to analyze such things as:

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash flows, 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 consolidated statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because 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 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 that EBITDAX assists our lenders and investors in comparing our 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. In addition, because we use capital assets, DD&A are also necessary elements of our costs. Finally, 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 EBITDAX for each of the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in Thousands)	2014			2013			2014			2013
Net Income From Continuing Operations	$	6,589		$	1,832		$	25,982		$	12,931
Net Income Attributable to Noncontrolling Interests		(895	)		(258	)		(3,340	)		(912	)
Income From Continuing Operations Attributable to Rex Energy		5,694			1,574			22,642			12,019
Add Back Depletion, Depreciation, Amortization and Accretion		27,364			16,267			69,014			40,367
Add Back Non-Cash Compensation Expense		1,521			1,365			4,245			3,788
Add Back Interest Expense		11,080			6,181			25,718			16,013
Add Back Impairment Expense		1			2,244			41			2,414
Add Back Exploration Expenses		1,462			3,242			4,890			7,511
Add Back (Less) Loss (Gain) on Disposal of Assets		84			140			385			(620	)
Add Back (Less) Loss (Gain) on Financial Derivatives		(12,316	)		4,624			(2,315	)		1,423
Add Back (Less) Cash Settlement of Derivatives		3,002			741			(3,331	)		5,540
Less Non-Cash Portion of Noncontrolling Interests		(410	)		(198	)		(1,184	)		(404	)
Add Back (Less) Income Tax Expense (Benefit)		4,469			(1,493	)		14,592			5,622
Add Back Non-Cash Portion of Equity Method Investments		201			195			603			555
EBITDAX From Continuing Operations	$	42,152		$	34,882		$	135,300		$	94,228
Net Income From Discontinued Operations	$	—		$	—		$	—		$	460
Add Back Exploration Expenses		—			—			—			97
Less Gain on Disposal of Assets		—			—			—			(969	)
Add Back Income Tax Expense		—			—			—			313
Add EBITDAX From Discontinued Operations	$	—		$	—		$	—		$	(99	)
EBITDAX (Non-GAAP)	$	42,152		$	34,882		$	135,300		$	94,129

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, NGLs and natural gas. We account for our natural gas and oil exploration and production activities under the successful efforts method of accounting. To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps and costless collars in order to establish some price floor protection.

For the three and nine months ended September 30, 2014, we received net settlements on oil, NGL and natural gas derivatives of approximately $3.0 million and paid net settlements of approximately $4.2 million, respectively, as compared to net receipts of approximately $0.7 million and $5.5 million for the comparable period in 2013, respectively. These gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. As of September 30, 2014, we had over 85.0% and 20.0% of our annualized 2014 oil production hedged through the remainder of 2014 and 2015, respectively, over 75.0% and 45.0% of our annualized 2014 natural gas production hedged through the remainder of 2014 and 2015, respectively, and over 60.0% of our annualized 2014 NGL production hedged through the remainder of 2014. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion activity or the natural decline of our oil and gas production.

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, NGLs and natural gas. We enter into all of our derivatives transactions with five counterparties and have a netting agreement in place with our counterparties. While we do not obtain collateral to support the agreements, we do monitor the financial viability of our counterparties and believe our credit risk is 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 derivatives 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, NGL and natural gas derivative positions at September 30, 2014, refer to Part I, Item 1. Financial Statements—Note 9, “Fair Value of Financial and Derivative Instruments”.

In addition to our capital expenditure program, we are committed to making cash payments in the future on various types of contracts and obligations. Our contractual obligations include long-term debt, operating leases, other loans and notes payable, derivative obligations, firm commitments under sales, gathering and processing agreements and asset retirement obligations. Since December 31, 2013, there have been no material changes to our contractual obligations, other than an increase in long-term debt due to our borrowings under the Senior Credit Facility. See Part I, Item 1. Financial Statements—Note 8, “Long-Term Debt” for additional information on the Senior Credit Facility.

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

We are exposed to various market risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial period of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, NGLs and natural gas. Conversely, increases in the market prices for oil, NGLs and natural gas can have a favorable impact on our financial condition, results of operations and capital resources. Based on production through September 30, 2014, we project that a 10% decline in the price per barrel of oil and NGLs and the price per Mcf of gas from the first nine months of the 2014 average would reduce our gross revenues, before the effects of derivatives, for the remaining three months of 2014 by approximately $7.6 million.

We have designed our hedging program to reduce the risk of price volatility for our production in the oil, NGL and natural gas markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include swaps, collars, put spreads, put options, basis swaps, swaptions and three way collars. The volume of derivative instruments that we may use are governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production, and will provide only partial price protection against declines in oil, NGL and natural gas prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of oil, NGLs and natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties should default, this protection might be limited as we might not receive the benefits of the hedges.

At September 30, 2014, we had the following commodity derivative contracts outstanding:

Period	Volume	Put Option		Floor		Ceiling		Swap			Long Call		Fair Market Value ($ in Thousands)
Oil
2014—Collar	15,000 Bbls	$	—	$	90.00	$	97.65	$	—		$	—	$	26
2014—Cap Swap	90,000 Bbls		80.83		—		—		97.72			—		649
2014—Three Way Collar	90,000 Bbls		77.92		88.98		103.39		—			—		171
2014—Deferred Put Spread	42,000 Bbls		75.00		90.00		—		—			—		(146	)
2015—Three Way Collar	120,000 Bbls		78.75		89.06		100.44		—			—		292
2015—Call Protected Swap	30,000 Bbls		—		—		—		95.76			110.00		228
2015—Put	930,000 Bbls		—		90.16		—		—			—		235
	1,317,000 Bbls												$	1,455
Natural Gas
2014—Call	450,000 Mcf	$	—	$	—	$	5.00	$	—		$	—	$	(7	)
2014—Three Way Collar	4,050,000 Mcf		3.55		4.19		4.69		—			—		556
2014—Swap	1,110,000 Mcf		—		—		—		3.96			—		(147	)
2014—Collar	450,000 Mcf		—		3.51		4.43		—			—		(23	)
2014—Swaption	600,000 Mcf		—		—		—		4.45			—		(35	)
2014—Basis Swap	1,500,000 Mcf		—		—		—		(0.37	)		—		1,889
2014—Cap Swap	900,000 Mcf		3.30		—		—		4.09			—		(17	)
2015—Three Way Collar	12,900,000 Mcf		3.63		4.16		4.61		—			—		707
2015—Swap	1,200,000 Mcf		—		—		—		4.18			—		180
2015—Cap Swap	2,400,000 Mcf		3.28		—		—		4.10			—		(28	)
2015—Call	2,400,000 Mcf		—		—		4.40		—			—		(528	)
2015—Swaption	0 Mcf		—		—		—		4.47			—		(505	)
2015—Basis Swap	1,200,000 Mcf		—		—		—		(0.56	)		—		973
2016—Three Way Collar	2,100,000 Mcf		3.60		4.08		4.52		—			—		(127	)
2017—Three Way Collar	1,200,000 Mcf		3.60		4.10		4.57		—			—		(82	)
	32,460,000 Mcf												$	2,806
NGLs
2014—Swap	261,000 Bbls	$	—	$	—	$	—	$	56.63		$	—	$	819
2015—Swap	258,000 Bbls		—		—		—		44.60			—		341
	519,000 Bbls												$	1,160

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and prime rate based, as determined by our lenders, and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our obligations. In the past, we have used an interest rate swap agreement to manage risk associated with interest payments on amounts outstanding from variable rate borrowing under our Senior Credit Facility; however, during the three months ended June 30, 2014, we terminated our interest rate swap for net proceeds of approximately $0.6 million. During the three and nine months ended September 30, 2014, we received cash payments of approximately $0 and $0.9 million, respectively, related to our interest rate swaps. Based on our total debt as of September 30, 2014 of approximately $692.4 million, a 1.0% change in interest rates would impact our interest expense by approximately $6.9 million.

We maintain disclosure controls and procedures that are designed to ensure that that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Such controls include those designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), to allow timely decisions regarding required disclosure.

Our management (with the participation of our CEO and CFO) has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our CEO and CFO have concluded that, as of September 30, 2014, our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our management, including our CEO and CFO, recognizes that the disclosure controls and procedures and internal controls (discussed above) cannot prevent all errors or all attempts at fraud. Any controls system, no matter how well-crafted and operated, can only provide reasonable, and not absolute, assurance of achieving the desired control objectives. Because of the inherent limitations in any control system, no evaluation or implementation of a control system can provide complete assurance that all control issues and all possible instances of fraud have been, or will be, detected.

The information set forth under the subsections Legal Reserves and Environmental in Note 13, Commitments and Contingencies, to our Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q is incorporated herein by reference.

During the quarter ended September 30, 2014, there were no material changes to the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2013, except as set forth below.

We are subject to various contractual limitations that may restrict our business and financing activities.

Our revolving credit facility, the indentures governing our Senior Notes and the certificate of designations governing our Series A Preferred Stock contain, and any future indebtedness we incur may contain, a number of restrictive covenants and limitations that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

Additionally, if dividends on our Series A Preferred Stock are in arrears and unpaid for six or more quarterly periods, the holders (voting as a single class) of our outstanding Series A Preferred Stock will be entitled to elect two additional directors to our Board of Directors until paid in full.

As a result of these covenants and restrictions, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with some of these covenants and restrictions may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants and restrictions may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facility, the indentures governing our Senior Notes or any future indebtedness could result in an event of default under our revolving credit facility, the indentures governing our Senior Notes or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. If an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder:

A payment default or an acceleration under our revolving credit facility could result in an event of default and an acceleration under the indentures for our Senior Notes.

If the indebtedness under the Senior Notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under our revolving credit facility are collateralized by perfected first priority liens and security interests on substantially all of our assets and if we are unable to repay our indebtedness under the revolving credit facility, the lenders could seek to foreclose on our assets.

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this Quarterly Report on Form 10-Q and incorporated herein by reference.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

Large Accelerated filer	x	Accelerated filer	¨

Non-accelerated filer	¨	Smaller Reporting Company	¨

			PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements	4
		Consolidated Balance Sheets As of September 30, 2014 (Unaudited) and December 31, 2013	4
		Consolidated Statements of Operations (Unaudited) for the three and nine-month periods ended September 30, 2014 and September 30, 2013	5
		Consolidated Statement of Changes in Noncontrolling Interests and Stockholders’ Equity (Unaudited) for the nine-month period ended September 30, 2014	6
		Consolidated Statements of Cash Flows (Unaudited) for the nine-month periods ended September 30, 2014 and September 30, 2013	7
		Notes to Consolidated Financial Statements (Unaudited)	8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	37
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	50
	Item 4.	Controls and Procedures	51
PART II. OTHER INFORMATION			53
	Item 1.	Legal Proceedings	53
	Item 1A.	Risk Factors	53
	Item 6.	Exhibits	54
SIGNATURES			55
EXHIBIT INDEX			56

($ in Thousands)	Nine Months Ended September 30, 2014
Beginning Balance at January 1, 2014	$	28,525
Future Abandonment Obligation Incurred		1,321
Future Abandonment Obligation Settled		(1,798	)
Future Abandonment Obligation Revision of Estimated Obligation		27
Future Abandonment Obligation Accretion Expense		2,912
Total Future Abandonment Cost¹	$	30,987

($ in Thousands)	September 30, 2014 (Unaudited)			December 31, 2013
8.875% Senior Notes Due 2020	$	350,000		$	350,000
6.25% Senior Notes Due 2022		325,000			—
Premium on Senior Notes, Net		2,816			3,078
Senior Line of Credit(a)		—			59,000
Capital Leases and Other Obligations(a)		14,633			9,934
Total Debt		692,449			422,012
Less Current Portion of Long-Term Debt		(8,248	)		(6,743	)
Total Long-Term Debt	$	684,201		$	415,269

2014	$	5,589
2015		2,745
2016		2,835
2017		2,003
2018		796
Thereafter		675,665
Total^(a)	$	689,633

($ in Thousands)	September 30, 2014
Evaluated Oil and Gas Properties	$	6,968
Unevaluated Oil and Gas Properties		88,351
Wells and Facilities in Progress		25,244
Purchase Price	$	120,563

			Fair Value Measurements at September 30, 2014 Using:
($ in Thousands)	Total Carrying Value as of September 30, 2014		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	5,421	$	—	$	2,559	$	2,862

		Outstanding				Exercisable
Exercise Price		Number Outstanding At 9/30/14		Weighted-Average Exercise Price		Number Exercisable At 9/30/14		Weighted-Average Exercise Price
$	5.04		46,041	$	5.04		46,041	$	5.04
$	9.50		85,000	$	9.50		85,000	$	9.50
$	9.99		149,333	$	9.99		149,333	$	9.99
$	10.42		29,548	$	10.42		29,548	$	10.42
$	11.87		3,500	$	11.87		3,500	$	11.87
$	12.50		19,139	$	12.50		19,139	$	12.50
$	13.19		50,000	$	13.19		—	$	-
$	22.34		30,000	$	22.34		30,000	$	22.34
			412,561	$	10.79		362,561	$	10.45

TSR Rank	Percentage of 2013 Awards to Vest
1-3		100	%
4-6		75	%
7-10		50	%
11-13		25	%
14-16		0	%

TSR Rank	Percentage of 2012 Awards to Vest
1-3		100	%
4-5		75	%
6-8		50	%
9-11		25	%
12-14		0	%

	Nine Months Ended September 30, 2014			Year Ended December 31, 2013
Expected Dividend Yield		0.0	%		0.0	%
Risk-Free Interest Rate		0.8	%		0.7	%
Expected Volatility – Rex Energy		50.4	%		50.5	%
Expected Volatility – Peer Group	28.4%-65.7%			28.4%-63.5%
Market Index		35.3	%		35.3	%
Expected Life	Three Years			Three Years

	Number of Shares			Weighted-Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2013		2,172,639		$	14.16
Awards		51,178			15.00
Forfeitures		(157,542	)		14.56
Vested		(315,680	)		12.58
Restricted stock awards, as of September 30, 2014		1,750,595		$	14.43

($ in Thousands)	Total
2014	$	4,372
2015		22,122
2016		34,428
2017		52,723
2018		55,539
Thereafter		752,689
Total	$	921,873

	<$2.25(a)		$2.26 - $2.99(a)		$3.00 - $4.99(a)		$5.00 - $5.99(a)		>$5.99(a)
Year One	$	40,000	$	45,000	$	50,000	$	55,000	$	60,000
Year Two	$	30,000	$	35,000	$	40,000	$	45,000	$	55,000
Year Three	$	25,000	$	30,000	$	30,000	$	40,000	$	50,000
Year 4 – 10	$	10,000	$	15,000	$	20,000	$	20,000	$	20,000
Year 11 – 15	$	5,000	$	5,000	$	10,000	$	10,000	$	10,000

	Wells Drilled				Wells Completed				Wells Placed In Service
	Gross		Net		Gross		Net		Gross		Net
Appalachian Basin		16.0		11.5		13.0		9.1		20.0		16.7
Illinois Basin		4.0		4.0		6.0		6.0		6.0		6.0
Total		20.0		15.5		19.0		15.1		26.0		22.7

	Other Performance Measurements
	For Three Months Ended September 30,				For Nine Months Ended September 30,
	2014		2013		2014		2013
EBITDAX from Continuing Operations ($ in Thousands) (a)	$	42,152	$	34,882	$	135,300	$	94,228
LOE per Mcfe	$	1.77	$	1.89	$	1.81	$	1.84
G&A per Mcfe	$	0.67	$	0.97	$	0.78	$	1.03

	REX ENERGY CORPORATION (Registrant)
Date: November 5, 2014	By:	/s/ Thomas C. Stabley
		Thomas C. Stabley
		Chief Executive Officer (Principal Executive Officer)

Exhibit Number		Exhibit Title
2.1		Purchase and Sale Agreement dated as of August 11, 2014 by and between R.E. Gas Development, LLC and SWEPI LP (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on September 15, 2014) (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission).
3.1		Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.2		Certificate of Amendment to Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.3		Certificate of Designations, Preferences, Rights and Limitations of 6.00% Convertible Perpetual Preferred Stock, Series A, of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K as filed with the SEC on August 18, 2014).
3.4		Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K as filed with the SEC on May 11, 2012).
3.5		Amendment to the Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K as filed with the SEC on August 18, 2014).
4.1		Form of Specimen Common Stock Certificate of Rex Energy Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).
4.2		Form of Registration Rights Agreement (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).
4.3		Indenture dated as of December 12, 2012 among Rex Energy Corporation, the Guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on December 12, 2012).
4.4		Form of 8.875% Senior Notes due 2020 (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on December 12, 2012, and incorporated herein by reference).
4.5		Registration Rights Agreement dated as of December 12, 2012 among Rex Energy Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed with the SEC on December 12, 2012).
4.6		Registration Rights Agreement, dated as of April 26, 2013, among Rex Energy Corporation, the Guarantors named therein, and RBC Capital Markets, LLC, KeyBanc Capital Markets Inc., SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC, on behalf of the initial purchasers named therein (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on April 26, 2013, and incorporated herein by reference).
4.7		Indenture dated as of July 17, 2014 among Rex Energy Corporation, the Guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on July 17, 2014).
4.8		Form of 6.250% Senior Notes due 2022 (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on July 17, 2014, and incorporated herein by reference).
4.9		Registration Rights Agreement dated as of July 17, 2014 among Rex Energy Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed with SEC on July 17, 2014).
4.10		Deposit Agreement, dated August 18, 2014, by and among the Company, Computershare Trust Company, N.A. and Computershare Inc., together as depositary, and holders from time to time of the depositary receipts described therein (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on August 18, 2014).
4.11		Form of Depositary Receipt Representing the Depositary Shares (included as Exhibit A to Exhibit 4.10) (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed with the SEC on August 18, 2014).
10.1*		Third Amendment to Amended and Restated Credit Agreement, effective as of July 11, 2014, by and among Rex Energy Corporation, KeyBank National Association, as Administrative Agent, and the other lenders signatory thereto.
10.2*		Amended and Restated Gas Gathering, Compression and Processing Agreement dated as of August 22, 2014 by and among R.E. Gas Development, LLC, MarkWest Liberty Bluestone, L.L.C. and Rex Energy Corporation (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission).

Exhibit Number		Exhibit Title
10.3*		Natural Gas Liquids Fractionation, Exchange and Marketing Agreement dated as of August 22, 2014 by and among R.E. Gas Development, LLC, MarkWest Liberty Midstream & Resources, L.L.C. and Rex Energy Corporation (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission).
10.4*		Fourth Amendment to Amended and Restated Credit Agreement, effective as of August 15, 2014, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and the other lenders signatory thereto.
10.5*		Fifth Amendment to Amended and Restated Credit Agreement effective as of September 12, 2014, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto.
31.1*		Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2*		Certification of Chief Financial Officer (Principal Financial Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.
32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.
32.2*		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document