Rex Energy 10-Q 2016 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2016

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             .

Commission file number: 001-33610

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	20-8814402
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification number)

366 Walker Drive

State College, Pennsylvania 16801

(Address of principal executive offices) (Zip Code)

(814) 278-7267

(Registrant’s telephone number, including area code)

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  ☒    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  ☒    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:

Large Accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller Reporting Company	☐

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

97,882,115 shares of common stock were outstanding on November 4, 2016.

REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD SEPTEMBER 30, 2016

INDEX

			PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements	4
		Consolidated Balance Sheets As of September 30, 2016 (Unaudited) and December 31, 2015	4
		Consolidated Statements of Operations (Unaudited) for the three and nine-month periods ended September 30, 2016 and September 30, 2015	5
		Consolidated Statement of Changes in Stockholders’ Equity (Unaudited) for the nine-month period ended September 30, 2016	6
		Consolidated Statements of Cash Flows (Unaudited) for the nine-month periods ended September 30, 2016 and September 30, 2015	7
		Notes to Consolidated Financial Statements (Unaudited)	8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	40
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	56
	Item 4.	Controls and Procedures	58
PART II. OTHER INFORMATION			59
	Item 1.	Legal Proceedings	59
	Item 1A.	Risk Factors	59
	Item 6.	Exhibits	59
SIGNATURES			60
EXHIBIT INDEX			61

2

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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:

• economic conditions in the United States and globally;

• domestic and global supply and demand for oil, natural gas liquids (“NGLs”) and natural gas;

• realized prices for oil, natural gas and NGLs and volatility of those prices;

• the adequacy and availability of capital resources, credit and liquidity, including, but not limited to, access to additional borrowing capacity and our inability to generate sufficient cash flow from operations to fund our capital expenditures and meet working capital needs;

• conditions in the domestic and global capital and credit markets and their effect on us;

• impairments of our natural gas and oil asset values due to declines in commodity prices;

• new or changing government regulations, including those relating to environmental matters, permitting or other aspects of our operations;

• the willingness and ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain oil price and production controls;

• the geologic quality of our properties with regard to, among other things, the existence of hydrocarbons in economic quantities;

• uncertainties inherent in the estimates of our oil, NGL and natural gas reserves;

• our ability to increase oil and natural gas production and income through exploration and development;

• drilling and operating risks;

• counterparty credit risks;

• the success of our drilling techniques in both conventional and unconventional reservoirs;

• the success of the secondary and tertiary recovery methods we utilize or plan to employ in the future;

• the number of potential well locations to be drilled, the cost to drill them, and the time frame within which they will be drilled;

• the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services;

• the availability of equipment, such as drilling rigs and infrastructure, such as transportation, pipelines, processing and midstream services;

• the effects of adverse weather or other natural disasters on our operations;

• competition in the oil and gas industry in general, and specifically in our areas of operations;

• changes in our drilling plans and related budgets;

• the success of prospect development and property acquisitions;

• the success of our business and financial strategies, and hedging strategies;

• uncertainties related to the legal and regulatory environment for our industry and our own legal proceedings and their outcome; and

• other factors discussed under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2015 filed with the Securities and Exchange Commission.

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.

3

Item 1. Financial Statements.

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

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

	September 30, 2016 (unaudited)			December 31, 2015
ASSETS
Current Assets
Cash and Cash Equivalents	$	2,524		$	1,091
Accounts Receivable		21,655			17,274
Taxes Receivable		211			18
Short-Term Derivative Instruments		5,461			34,260
Inventory, Prepaid Expenses and Other		1,079			3,059
Assets Held for Sale		—			60,451
Total Current Assets		30,930			116,153
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,020,993			943,092
Unevaluated Oil and Gas Properties		223,791			262,992
Other Property and Equipment		21,449			20,363
Wells and Facilities in Progress		66,614			141,100
Pipelines		15,186			14,024
Total Property and Equipment		1,348,033			1,381,571
Less: Accumulated Depreciation, Depletion and Amortization		(459,549	)		(437,828	)
Net Property and Equipment		888,484			943,743
Other Assets		2,492			2,501
Long-Term Derivative Instruments		3,367			9,534
Total Assets	$	925,273		$	1,071,931
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	29,464		$	36,785
Current Maturities of Long-Term Debt		201			402
Accrued Liabilities		29,619			40,608
Short-Term Derivative Instruments		9,294			2,486
Liabilities Related to Assets Held for Sale		631			36,320
Total Current Liabilities		69,209			116,601
Long-Term Derivative Instruments		3,354			5,556
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		126,061			109,386
Senior Notes, Net of Issuance Costs and Deferred Gain on Debt Exchanges		633,322			663,089
Premium on Senior Notes, Net		134			2,344
Other Deposits and Liabilities		9,617			3,156
Future Abandonment Cost		7,438			11,568
Total Liabilities	$	849,135		$	911,700
Commitments and Contingencies (See Note 12)
Stockholders’ Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 4,087    issued and outstanding on September 30, 2016 and 16,100 shares issued and    outstanding on December 31, 2015	$	1		$	1
Common Stock, $.001 par value per share, 200,000,000 shares authorized and    95,886,983 shares issued and outstanding on September 30, 2016 and 55,741,229    shares issued and outstanding on December 31, 2015		94			54
Additional Paid-In Capital		649,103			623,863
Accumulated Deficit		(573,060	)		(463,687	)
Total Stockholders’ Equity		76,138			160,231
Total Liabilities and Stockholders’ Equity	$	925,273		$	1,071,931

See accompanying notes to the unaudited consolidated financial statements

4

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, $ in Thousands, Except per Share Data)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2016			2015			2016			2015
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	34,034		$	29,648		$	90,978		$	111,344
Other Operating Revenue		5			8			12			30
TOTAL OPERATING REVENUE		34,039			29,656			90,990			111,374
OPERATING EXPENSES
Production and Lease Operating Expense		26,333			24,259			76,005			71,646
General and Administrative Expense		5,116			4,507			15,237			20,253
(Gain) Loss on Disposal of Assets		10			(224	)		(4,285	)		(533	)
Impairment Expense		9,563			85,193			45,344			209,880
Exploration Expense		216			580			1,954			1,774
Depreciation, Depletion, Amortization and Accretion		15,109			20,832		��	46,371			67,369
Other Operating Expense		9,899			190			10,930			5,328
TOTAL OPERATING EXPENSES		66,246			135,337			191,556			375,717
LOSS FROM OPERATIONS		(32,207	)		(105,681	)		(100,566	)		(264,343	)
OTHER INCOME (EXPENSE)
Interest Expense		(9,646	)		(11,884	)		(34,115	)		(36,077	)
Gain (Loss) on Derivatives, Net		16,866			28,649			(8,254	)		45,487
Other Income		16			25			28			118
Debt Exchange Expense		(35	)		—			(9,048	)		—
Gain on Extinguishments of Debt		423			—			24,130			—
Loss on Equity Method Investments		—			—			—			(411	)
TOTAL OTHER INCOME (EXPENSE)		7,624			16,790			(27,259	)		9,117
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(24,583	)		(88,891	)		(127,825	)		(255,226	)
Income Tax Benefit		8,106			—			5,785			—
NET LOSS FROM CONTINUING OPERATIONS		(16,477	)		(88,891	)		(122,040	)		(255,226	)
Income (Loss) From Discontinued Operations, Net of Income Taxes		21,892			(5,785	)		12,719			(7,770	)
NET INCOME (LOSS)		5,415			(94,676	)		(109,321	)		(262,996	)
Net Income (Loss) Attributable to Noncontrolling Interests		—			(1	)		—			2,245
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	5,415		$	(94,675	)	$	(109,321	)	$	(265,241	)
Preferred Stock Dividends		(613	)		(2,415	)		(4,441	)		(7,245	)
Effect of Preferred Stock Conversions		—			—			72,316			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	4,802		$	(97,090	)	$	(41,446	)	$	(272,486	)
Earnings per common share:
Basic – Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(0.19	)	$	(1.69	)	$	(0.74	)	$	(4.88	)
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.24			(0.11	)		0.17			(0.19	)
Basic – Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	0.05		$	(1.80	)	$	(0.57	)	$	(5.07	)
Basic – Weighted Average Shares of Common Stock Outstanding		90,803			53,936			73,098			53,748
Diluted – Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(0.19	)	$	(1.69	)	$	(0.74	)	$	(4.88	)
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.24			(0.11	)		0.17			(0.19	)
Diluted – Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	0.05		$	(1.80	)	$	(0.57	)	$	(5.07	)
Diluted – Weighted Average Shares of Common Stock Outstanding		90,803			53,936			73,098			53,748

See accompanying notes to the unaudited consolidated financial statements

5

REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

FOR THE NINE-MONTHS ENDED SEPTEMBER 30, 2016

(Unaudited, in Thousands)

	Common Stock					Preferred Stock
	Shares			Par Value		Shares			Par Value		Additional Paid-In Capital			Accumulated Deficit			Total Stockholders’ Equity
BALANCE December 31, 2015		55,741		$	54		16		$	1	$	623,863		$	(463,687	)	$	160,231
Non-Cash Compensation		—			—		—			—		1,899			—			1,899
Issuance of Common Stock in Debt Exchange		8,413			8		—			—		6,404			—			6,412
Issuance of Common Stock for Debt Extinguishments		22,683			22		—			—		16,894			—			16,916
Preferred Stock Dividends settled in Common Shares		62			—		—			—		52			(52	)		—
Issuance of Restricted Stock, Net of    Forfeitures		(24	)		1		—			—		—			—			1
Conversion of Preferred Stock to Common Stock		9,012			9		(12	)		—		(9	)		—			—
Net Loss		—			—		—			—		—			(109,321	)		(109,321	)
BALANCE September 30, 2016		95,887		$	94		4		$	1	$	649,103		$	(573,060	)	$	76,138

See accompanying notes to the unaudited consolidated financial statements

6

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

	For the Nine Months Ended     September 30,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(109,321	)	$	(262,996	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments		—			411
Non-cash Expenses		17,143			5,691
Depreciation, Depletion, Amortization and Accretion		51,471			82,866
(Gain) Loss on Derivatives		8,254			(45,487	)
Cash Settlements of Derivatives		32,485			40,102
Non-cash Exploration Expenses		872			468
Impairment Expense		48,887			264,677
Gain on Extinguishments of Debt		(24,213	)		—
Gain on Sale of Assets		(34,820	)		(509	)
Gain on Sale of Water Solutions Holdings		—			(57,014	)
Changes in operating assets and liabilities
Accounts Receivable		(2,580	)		12,015
Inventory, Prepaid Expenses and Other Assets		2,374			1,092
Accounts Payable and Accrued Liabilities		(7,781	)		(26,103	)
Other Assets and Liabilities		(1,244	)		(1,794	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(18,473	)		13,419
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		—			54
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		40,809			76,251
Proceeds from Joint Venture for Reimbursement of Capital Costs		19,461			16,611
Acquisitions of Undeveloped Acreage		(6,302	)		(26,511	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(48,640	)		(163,207	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		5,328			(96,802	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit		(35,230	)		(108,335	)
Proceeds from Long-Term Debt and Line of Credit		55,400			186,813
Repayments of Loans and Other Notes Payable		(568	)		(1,337	)
Debt Issuance Costs		(5,024	)		(629	)
Dividends Paid on Preferred Stock		—			(7,245	)
Distributions to Noncontrolling Interest Partners of Water Solutions Holdings		—			(830	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		14,578			68,437
NET INCREASE (DECREASE) IN CASH		1,433			(14,946	)
CASH – BEGINNING		1,091			18,096
CASH – ENDING	$	2,524		$	3,150
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	$	2,524		$	3,150
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	$	25,833		$	33,686
Cash Paid (Received) for Income Taxes	$	29		$	(502	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment Attributable to Discontinued Operations	$	1,341		$	20,044
NON-CASH ACTIVITIES
Fair value of contingent consideration receivable - sale of Illinois Basin	$	(1,166)		$	-
Decrease in Accrued Liabilities for Capital Expenditures	$	(5,912	)	$	(8,651	)
Increase Long Term Debt - Equipment Financing	$	816		$	-
Decrease in Senior Notes net of Issuance Costs, Deferred Gain on Exchanges, and    Net Premium due to Debt to Equity Conversions	$	(46,248	)	$	-
Decrease in  Bond Interest Payable due to Debt to Equity Conversions	$	(870	)	$	-
Increase in Common Stock outstanding due to Debt to Equity Conversions	$	16,916		$	-

See accompanying notes to the unaudited consolidated financial statements

7

REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

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 Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. 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.

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. We report our interests in oil, NGL and natural gas properties using the proportional consolidation method of accounting. All 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 Consolidated Financial Statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

For purposes of compliance with Accounting Standards Update (“ASU”) 2015-3, which we adopted on January 1, 2016, we have reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and approximately $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. In addition, we adopted ASU 2015-17 on January 1, 2016, which eliminates the need to show deferred tax liabilities and assets as current and noncurrent. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero (see Note 5, Recently Issued Accounting Pronouncements, to our Consolidated Financial Statements for additional information). For purposes of consistency, we have reclassified $350.0 million and $325.0 million from 8.875% Senior Notes Due 2020 and 6.25% Senior Notes Due 2022, respectively, to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015.

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 impact of 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, 2015.

Discontinued Operations

In June 2016, we entered into a purchase and sale agreement to divest all of our Illinois Basin assets and operations. The sale closed in August 2016, with an effective date of July 1, 2016.  As a result of this transaction, we have classified all of our assets and operations associated with the Illinois Basin sale as Discontinued Operations in the accompanying consolidated financial statements.

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 3, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

8

2. FUTURE ABANDONMENT COST

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

Accretion expense totaled $0.1 million and $0.5 million for the three and nine months ended September 30, 2016, respectively, and $0.3 million and $0.8 million for the three and nine months ended September 30, 2015, 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.

($ in Thousands)	September 30, 2016
Beginning Balance at January 1, 2016	$	11,934
Future Abandonment Obligation Incurred		514
Future Abandonment Obligation Settled		(17	)
Future Abandonment Obligation Cancelled or Sold		(4,815	)
Future Abandonment Obligation Revision of Estimated Obligation		350
Future Abandonment Obligation Accretion Expense		500
Total Future Abandonment Cost1	$	8,466

¹ Includes approximately $1.0 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

3. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

Water Solutions Holdings, LLC

In December 2014, our board of directors approved a formal plan to sell Water Solutions Holdings, LLC (“Water Solutions”), of which we owned a 60% interest. In June 2015, we entered into a purchase and sale agreement with American Water Works Company, Inc. (“American Water”) pursuant to which American Water acquired Water Solutions for consideration of approximately $130.0 million, inclusive of cash and debt and subject to other customary adjustments. The sale closed in July 2015, and we received approximately $66.8 million in net proceeds, resulting in a gain of approximately $57.8 million. The transaction was recorded as Discontinued Operations in 2015.

Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such indirect 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)	2016		2015			2016		2015
Revenues:
Field Services Revenue	$	—	$	1,479		$	—	$	33,086
Total Operating Revenue		—		1,479			—		33,086
Costs, Expenses and (Other Income):
General and Administrative Expense		—		82			—		1,961
Depreciation, Depletion, Amortization and Accretion		—		2			—		78
Field Services Operating Expense		—		1,229			—		25,981
Gain on Sale of Asset		—		(2	)		—		(44	)
Interest Expense		—		56			—		487
Other Income		—		(56,957	)		—		(56,836	)
Total Costs, Expenses and (Other Income)		—		(55,590	)		—		(28,373	)
Income from Discontinued Operations Before Income Taxes		—		57,069			—		61,459
Income Tax Expense		—		(2,416	)		—		(2,658	)
Income from Discontinued Operations, net of taxes	$	—	$	54,653		$	—	$	58,801

Illinois Basin Operations

9

On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). Pursuant to the Agreement, Campbell agreed to purchase, subject to certain parameters and provisions for adjustment customary for transactions of this type, all of Rex’s oil and gas-related properties and assets, both operated and non-operated, in the Illinois Basin on an as-is, where-is basis. Closing occurred on August 18, 2016, with an effective date for the transaction of July 1, 2016. We received a purchase deposit of $2.5 million from Campbell in June and received the additional proceeds of approximately $38.0 million during the third quarter (subject to customary closing and post-closing adjustments scheduled to occur during the fourth quarter). An addendum executed in conjunction with the Agreement allows for Rex to receive from Campbell potential additional proceeds of up $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ending December 31, 2016, and ending with the quarter ending June 30, 2019.  For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. For additional information, see Note 8, Derivative Instruments and Fair Value Measurements, to our Consolidated Financial Statements.

Calendar Quarter Ending	West Texas Intermediate ("WTI")  Average Price per Bbl (a)
12/31/2016	$	54.25
3/31/2017	$	56.25
6/30/2017	$	58.25
9/30/2017	$	60.25
12/31/2017	$	60.75
3/31/2018	$	61.25
6/30/2018	$	61.75
9/30/2018	$	62.25
12/31/2018	$	62.75
3/31/2019	$	63.25
6/30/2019	$	63.75

(a) Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays).

Included in the sale were approximately 76,000 net acres in Illinois, Indiana and Kentucky and production of approximately 1,700 net barrels per day.  The sale transaction resulted in a full divestiture of our Illinois Basin assets, and an exit from our Illinois Basin operations.  As of June 14, 2016, the Illinois Basin assets became classified as “Held for Sale”, and our assets and operations in the Illinois Basin are reported as Discontinued Operations.

10

The carrying value of assets and liabilities of our Illinois Basin operations that are classified as Held for Sale in the accompanying Consolidated Balance Sheets at September 30, 2016 and December 31, 2015 are as follows:

	September 30,			December 31,
($ in Thousands)	2016			2015
Assets:
Accounts Receivable	$	—		$	2,209
Inventory, Prepaid Expenses and Other		—			770
Total Current Assets		—			2,979
Evaluated Oil & Gas Properties		—			296,338
Other Property and Equipment		—			19,749
Wells and Facilities in Progress		—			3,456
Accumulated Depreciation, Depletion, and Amortization		—			(262,071	)
Total Long-Term Assets		—			57,472
Total Assets Held for Sale	$	-		$	60,451
Liabilities:
Accounts Payable	$	475		$	1,089
Current Maturities of Long-Term Debt		—			188
Accrued Liabilities		156			3,718
Total Current Liabilities		631			4,995
Long-Term Debt		—			10
Future Abandonment Cost		—			31,315
Total Long-Term Liabilities		—			31,325
Total Liabilities Related to Assets Held for Sale	$	631		$	36,320
Net Assets Held for Sale	$	(631	)	$	24,131

Summarized financial information for Discontinued Operations related to our Illinois Basin operations is set forth in the tables below, and does not reflect the costs of certain services provided. Such indirect 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. The sale of our Illinois assets and operations does not include any of our derivative contracts or positions related to our Illinois Basin revenues or production.  No derivative positions or activity has been attributed to or included in Discontinued Operations for the three and nine month periods ended September 30, 2016 and 2015.

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in Thousands)	2016			2015			2016			2015
Revenues:
Oil Sales	$	69		$	7,917		$	11,283		$	26,092
Total Operating Revenue		69			7,917			11,283			26,092
Costs and Expenses:
Production and Lease Operating Expense		261			6,350			10,987			18,641
General and Administrative Expense		33			869			1,471			3,254
(Gain) Loss on Disposal of Assets		(30,491	)		(5	)		(30,535	)		68
Impairment Expense		—			54,619			3,543			54,797
Exploration Expense		—			227			143			468
Depreciation, Depletion, Amortization and Accretion		18			6,292			5,100			15,419
Interest Expense		1			3			4			20
Other (Income) Expense		1			—			(1	)		(4	)
Total Costs and Expenses		(30,177	)		68,355			(9,288	)		92,663
Income (Loss) from Discontinued Operations Before Income Taxes		30,246			(60,438	)		20,571			(66,571	)
Income Tax Expense		(8,354	)		—			(7,852	)		—
Income (Loss) from Discontinued Operations, net of taxes	$	21,892		$	(60,438	)	$	12,719		$	(66,571	)
Production:
Crude Oil (Bbls)		1,688			182,787			310,408			545,328

11

4. BUSINESS AND OIL AND GAS PROPERTY DISPOSITIONS

Water Solutions

As described in Note 3 Discontinued Operations/Assets Held for Sale, we sold Water Solutions pursuant to a purchase and sale agreement with American Water.  

ArcLight Capital Partners, LLC

On March 31, 2015, we entered into a joint venture agreement with an affiliate of ArcLight Capital Partners, LLC (“ArcLight”) to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. ArcLight agreed to participate in and fund 35.0% of the estimated well costs for the designated wells. We expect to receive consideration for the transaction of approximately $67.0 million, with $16.6 million received at closing for wells that had previously been completed or were at that time in the process of being drilled and completed. The remainder of the proceeds will be received as additional wells are drilled and placed in sales. Upon the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest will revert back to us, leaving ArcLight with a 17.5% working interest. As of September 30, 2016, ArcLight had paid approximately $61.4 million for its interest in wells that have been drilled. As of September 30, 2016, all wells to be developed with ArcLight had been drilled and completed with four wells remaining to be placed into service.

The ArcLight transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by ArcLight. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from ArcLight are considered a recovery of costs and no gain or loss is recognized.

Benefit Street Partners, LLC

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, 12 of which have already been drilled, completed, placed in sales and paid for by BSP. The remaining four wells are expected to be placed in sales and paid for by BSP during the fourth quarter of 2016. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells in 2016 and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 20 of these additional wells, including four that were already drilled.  We expect total consideration for this transaction to be $175.0 million with approximately $120.7 million committed as of September 30, 2016. BSP has paid approximately $52.4 million for its interest in elected wells as of September 30, 2016. The remainder of the proceeds will be received as additional wells are drilled to total depth or placed in sales.  BSP earns an assignment of 15%-20% working interest in acreage located within each of the units in which it participates. As of September 30, 2016, 20 of the 42 committed wells were in line and producing, nine wells were drilled and awaiting completion and four wells were awaiting pipeline connection.

The BSP transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by BSP. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from BSP are considered a recovery of costs and no gain or loss is recognized.

Diversified Oil & Gas, LLC

On May 20, 2016, we entered into a Purchase and Sale Agreement (“PSA”) with Diversified Oil and Gas, LLC (“DOG”). Pursuant to the PSA, DOG purchased all of our conventional operated oil and gas-related properties and related pipeline assets located in Pennsylvania and assumed all future abandonment liability associated with the assets. Closing occurred on May 20, 2016, with an effective date for the transaction of May 1, 2016. We received proceeds at closing of approximately $51,000. Included in the sale were approximately 300 wells, pipelines and support equipment. The sale of well properties generated approximately $4.6 million of gain in the second quarter of 2016 due to the elimination of our future abandonment liability associated with wells and pipelines sold to DOG.  The gain, which is included in Gain on Disposal of Assets on our Consolidated Statement of Operations, is reported net of approximately $0.2 million of uncollectible accounts receivable written off in conjunction with the sale.

Illinois Basin Operations

As described in Note 3, Discontinued Operations/Assets Held for Sale, we sold our Illinois Basin assets and operations pursuant to a purchase and sale agreement with Campbell in August 2016.

12

5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40). The guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments in this ASU intend to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. In addition to reducing the number of consolidation models from four to two, the new standard places more emphasis on risk of loss when determining a controlling financial interest, reduces the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity and changes consolidation conclusions in several industries that typically make use of limited partnerships or variable interest entities. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The standard requires an entity to present debt issuance costs related to a recognized liability as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. We adopted this ASU on January 1, 2016. In conjunction with the adoption of ASU 2015-03, we reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. Adoption did not have an impact on Net Income or Accumulated Deficit.

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:

1) Identify the contract(s) with a customer.

2) Identify the performance obligations in the contract.

3) Determine the transaction price.

4) Allocate the transaction price to the performance obligations in the contract.

5) Recognize revenue when (or as) the entity satisfies a performance obligation.

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

1) Retrospectively to each prior reporting period presented.

2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications.

In July 2015, the FASB approved a one-year deferral of the effective date of this new standard so the guidance is effective for the reporting period beginning January 1, 2018, with early adoption permitted in the first quarter 2017. We are currently evaluating the new guidance and have not determined the impact this standard may have on our Consolidated Financial Statements or decided upon the method of adoption.

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. We adopted this ASU on January 1, 2016. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Deferred Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero. Adoption did not have an impact on Net Income or Accumulated Deficit.

13

In February 2016, the FASB issued ASU 2016-02, Leases. Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date:

• A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and

• A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating this guidance and do not believe it will have a material impact due to our minimal number of operating leases.

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. Under this update, several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. We are currently evaluating the impact of this standard.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The amendments in the update provide guidance regarding the presentation in the statement of cash flows of eight specific cash flow disclosure issues:

• debt prepayment or debt extinguishment costs;

• settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing;

• contingent consideration payments made after a business combination;

• proceeds from the settlement of insurance claims;

• proceeds from the settlement of corporate-owned life insurance policies;

• distributions received from equity method investees;

• beneficial interest in securitization transactions; and

• separately identifiable cash flows and application of the Predominance Principle.

Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The amendments should be applied using a retrospective transition method to each period presented. We are currently evaluating this guidance to assess its impact on our current cash flow reporting processes.

6. CONCENTRATIONS OF CREDIT RISK

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 7, 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 8, Derivative Instruments and Fair Value Measurements, 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, 2016, approximately 88.9% of our commodity sales came from four purchasers, with the largest single purchaser accounting for 45.0% of commodity sales.  

14

7. LONG-TERM DEBT

Senior Credit Facility

We maintain a revolving credit facility, evidenced by a credit agreement dated March 27, 2013 and most recently amended on July 1, 2016 (the “Senior Credit Facility”). As of September 30, 2016, the borrowing base under the Senior Credit Facility was $190.0 million. The borrowing base under our Senior Credit Facility may be increased to up to $400.0 million with consent of the lenders and other conditions prescribed by the agreement upon redeterminations of the borrowing base. In addition, the borrowing base contains a $60.0 million sublimit for letters of credit.  Effective October 3, 2016, our borrowing base was reaffirmed at $190.0 million in connection with our scheduled redetermination. As of September 30, 2016, loans outstanding under the Senior Credit Facility were set to mature on September 12, 2019. Availability under our Senior Credit Facility is limited by a borrowing base, which is redetermined at least semi-annually by our lenders with the next scheduled redetermination on or about April 1, 2017. In certain circumstances, we may be required to prepay the loans, however, management does not believe that a prepayment will be required within the next twelve months. As of September 30, 2016, we had $131.7 million borrowings outstanding, and approximately $42.9 million in outstanding undrawn letters of credit. There were $111.5 million borrowings outstanding as of December 31, 2015. Our Senior Credit Facility restricts the amount of cash and cash equivalents that we can hold on our Consolidated Balance Sheet to a maximum of $15.0 million. Any excess must be used to pay down the outstanding loans; however, we retain the right to redraw such amounts so long as availability exists under our borrowing base.

The Senior Credit Facility requires we meet certain financial requirements, on a quarterly basis, including a minimum current ratio, maximum “Net Senior Secured Debt” to EBITDAX ratio and minimum “Total PDP PV-9” to net senior secured debt ratio (all terms in quotations as defined in the Senior Credit Facility). EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, including our 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 or non-recurring activities. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, including the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day (the “Current Ratio”), must not be less than 1.0 to 1.0. Our Current Ratio as of September 30, 2016 was approximately 1.4 to 1.0.Additionally, as of the last day of any fiscal quarter, our ratio of “Net Senior Secured Debt” to EBITDAX for the trailing twelve months must not exceed 2.75 to 1.0. Our ratio of Net Senior Secured Debt to EBITDAX as of September 30, 2016 was approximately 2.70 to 1.0.  Beginning September 30, 2016, we were also required to meet a minimum ratio of “Total PDP PV-9” at the “Forward Strip Commodity Price” as of each date of determination to “Net Senior Secured Debt” (the “PDP Coverage Ratio”) of at least 1.65 to 1.0.  Our PDP Coverage Ratio as of September 30, 2016 was approximately 2.9 to 1.0.Our Senior Credit Facility also contains a requirement limiting our aggregate trailing twelve month net capital expenditures during any fiscal quarter in 2016 and 2017 to $65 million unless our PDP Coverage Ratio exceeds 2.0 to 1.0. Management currently anticipates being in compliance with these financial covenants at December 31, 2016 and beyond.      

In order to improve our liquidity positions to meet the financial requirements under our Senior Credit Facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, and/or other financing or strategic counterparties, which may include refinancing of existing debt, debt-for-debt or debt-for-equity exchanges, or other in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity will be raised from any such transactions or that any such transactions can or will be consummated within the period needed to meet our obligations.

Senior Notes

On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Senior Secured Second Lien Notes (the “New Notes”) and (ii) 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the New Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established.  See Note 9, Income Taxes, to our Consolidated Financial Statements, for information regarding the tax treatment and impact of the Exchange for federal and state income tax purposes.

In exchange for $324.0 million in aggregate principal amount of the 2020 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.2 million aggregate principal amount of New Notes and (ii) 8.4 million shares, which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of New Notes were issued to holders who were ineligible to accept Shares. In

15

addition, upon closing, we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The remaining Existing Notes will continue to accrue interest at their historical rates. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum thereafter, payable in cash. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending October 1, 2020. In connection with the Exchange, we incurred approximately $0.1 million and $9.0 million in third-party debt issuance costs, in the three and nine-month periods ending September 30, 2016, respectively. These costs were recorded as Debt Exchange Expense in our Consolidated Statement of Operations.

Following the completion of the Exchange, we entered into debt-for equity exchanges with certain holders of our Existing Notes, as well as holders of our New Notes, in exchange for unrestricted shares of our common stock.  These exchanges resulted in the retirement of $27.7 million of our remaining Existing Notes and $45.7 million of our outstanding New Notes, in exchange for the issuance of a total of approximately 22.7 million shares of unrestricted common stock.  The exchanged notes were subsequently cancelled, resulting in a gain to the Company for the three and nine month periods ending September 30, 2016 of approximately $0.4 million and $24.1 million, respectively, presented as Gain on Extinguishment of Debt in our Consolidated Statements of Operations.

We may redeem, at specified redemption prices, some or all of the New Notes at any time on or after April 1, 2018. We may also redeem up to 35% of the New Notes using the proceeds of certain equity offerings completed before April 1, 2018. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the Existing Notes and the New Notes from the holders.

Our Existing Notes and New Notes (collectively, the “Senior Notes”) are recorded as Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets.

The Senior Notes are represented by indentures (the “Indentures”), which contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted.  Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25 to 1.00.  As of September 30, 2016, our Fixed Charge Coverage Ratio was 1.20 to 1.00.We expect our Fixed Charge Coverage Ratio to improve based on our projections of decreased interest expense related to the New Notes. As of September 30, 2016, we were limited to incurring an additional $109.2 million in debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the individual Trustees or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.  

As of September 30, 2016 and December 31, 2015, we had recorded on our Consolidated Balance Sheets approximately $0.1 million and $2.3 million, respectively, of a net premium related to the Senior Notes. The amortization of our net premium during the three and nine-month periods ended September 30, 2016, which follows the effective interest method, was approximately $1.3 million and $1.4 million, respectively, and was recorded as a credit to Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is paid at a rate of 8.875% per annum on June 1 and December 1 of each year, while interest on the 2022 Notes is paid at a rate of 6.25% per annum on February 1 and August 1 of each year.

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, 2016 and December 31, 2015:

($ in Thousands)	September 30, 2016 (Unaudited)			December 31, 2015
Senior Notes, Net of Issuance Costs and Deferred Gain on Debt Exchanges (a)(c)	$	633,322		$	663,089
Premium on Senior Notes, Net		134			2,344
Senior Line of Credit, Net of Issuance Costs (b)(d)		125,396			109,396
Capital Leases and Other Obligations(c)(d)		866			419
Total Debt		759,718			775,248
Less Current Portion of Long-Term Debt		(201	)		(402	)
Total Long-Term Debt	$	759,517		$	774,846

^(a) Includes unamortized debt issuance costs of approximately $1.3 million and $11.9 million as of September 30, 2016 and December 31, 2015, respectively.

^(b) Includes unamortized debt issuance costs of approximately $6.3 million and $2.1 million as of September 30, 2016 and December 31, 2015, respectively.

^(c) Includes unamortized deferred gain on debt exchange of approximately $32.5 million as of September 30, 2016, as a result of debt exchange transactions completed in the three months ending September 30, 2016.

16

^(d) The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. The weighted average interest rate on borrowings under our Senior Credit Facility for the three and nine months ended September 30, 2016, was approximately 4.0 % and 3.7%, respectively. The average interest rate on our capital leases and other obligations for the three and nine months ended September 30, 2016, was approximately 17.4%and 9.8%, respectively.

The following is the principal maturity schedule for debt outstanding as of September 30, 2016:

2016	$	100
2017		135
2018		155
2019		131,857
2020		596,316
Thereafter		6,099
Total(a)	$	734,662

(a) Excludes $0.1 million net premium on Senior Notes, $32.5 million of deferred gain on Senior Notes, and $7.6 million of debt issuance costs

8. DERIVATIVE INSTRUMENTS AND FAIR VALUE MEASUREMENTS

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, 2016 and December 31, 2015, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, calls, 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.

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 6, 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 $2.1 million and $32.5 million in relation to our commodity derivatives during the three and nine months ended September 30, 2016, respectively, and received net cash settlements of $15.1 million and $39.2 million in relation to our commodity derivatives during the three and nine months ended September 30, 2015, respectively.

As of September 30, 2016, we had over 100.0% of our annualized condensate production hedged through the remainder of 2016, over 90.0% and 65.0% of our annualized natural gas production hedged through the remainder of 2016 and 2017, respectively, and over 50.0% of our annualized NGL production hedged through the remainder of 2016. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion or the natural decline of our natural gas, condensate and NGL production.

Contingent Consideration – Sale of Illinois Basin Operations

In conjunction with the sale of our Illinois Basin operations, we executed a contract with the buyer that would allow us to receive future cash payments from the buyer if index pricing targets as defined in the contract are achieved at specified future dates.  See Note3, Discontinued Operations / Assets Held for Sale, to our Consolidated Financial Statements for additional information regarding the terms of the contract. We have evaluated the contract and concluded that it meets the definition and requirements for accounting treatment as a derivative instrument, as prescribed in ASC 815-10-15-83. We have recorded the contract at its initial fair value of approximately $1.2 million as additional consideration in the calculation of the gain on the sale of the assets. Fair value was determined through application of mathematical models designed to provide fair value estimates utilizing probability measures and the market index measures underlying the contract. The fair value will be adjusted at each future reporting period for the duration of the contract, which concludes June 30, 2019.

17

Interest Rate Derivatives

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, 2016, and December 31, 2015, we had $131.7 million and $111.5 million outstanding under our Senior Credit Facility, respectively, which is subject to variable rates of interest and $602.1 million of Senior Notes outstanding subject to fixed interest rates. See Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information on our Senior Credit Facility and Senior Notes.

As of September 30, 2016 and December 31, 2015, we did not have any interest rate derivatives outstanding. We utilize the mark-to-market accounting method to account for interest rate swap and swaptions. We recognize all gains and losses related to interest rate derivatives in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. During the three and nine months ended September 30, 2015, we received cash payments of approximately $0.1 million and $0.9 million, respectively, related to our interest rate swaps and swaptions.

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, 2016 and 2015:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
($ in Thousands)	2016			2015			2016			2015
Oil	$	1,214		$	5,599		$	(955	)	$	5,648
Natural Gas		13,540			12,013			238			28,649
NGLs		2,126			10,068			(7,589	)		10,441
Refined Products		(14	)		(180	)		52			(185	)
Interest Rate		—			1,149			—			934
Gain (Loss) on Derivatives, Net	$	16,866		$	28,649		$	(8,254	)	$	45,487

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 liability of approximately $3.8 million and a net asset of approximately $35.8 million at September 30, 2016 and December 31, 2015, respectively.

18

Our open asset/(liability) financial commodity derivative instrument positions at September 30, 2016 consisted of:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2016 - Collars		60,000	Bbls	$	—	$	37.50	$	49.05	$	—		$	(149	)
2016 - Three-Way Collars		60,000	Bbls		26.50		35.50		44.50		—			(328	)
2016 - Cap Swaps		30,000	Bbls		30.00		—		—		44.00			(162	)
		150,000	Bbls										$	(639	)
Natural Gas
2016 - Swaps		4,125,000	Mcf		—		—		—		2.81		$	(850	)
2016 - Swaptions		300,000	Mcf		—		—		—		3.15			(42	)
2016 - Cap Swaps		1,200,000	Mcf		2.59		—		—		3.07			(252	)
2016 - Collars		1,360,000	Mcf		—		2.59		2.99		—			(189	)
2016 - Three-Way Collars		905,000	Mcf		2.15		2.73		3.42		—			(67	)
2016 - Put Spreads		2,555,000	Mcf		2.56		3.32		—		—			341
2016 - Basis Swaps - Dominion South		2,925,000	Mcf		—		—		—		(0.90	)		1,248
2017 - Swaps		7,460,000	Mcf		—		—		—		3.09			381
2017 - Swaptions		-	Mcf		—		—		—		—			(350	)
2017 - Cap Swaps		3,900,000	Mcf		2.35		—		—		2.81			(1,345	)
2017 - Three-Way Collars		17,510,000	Mcf		2.33		3.01		3.87		—			1,253
2017 - Calls		3,000,000	Mcf		—		—		3.64		—			(939	)
2017 - Collars		1,400,000	Mcf		—		2.40		3.10		—			(267	)
2017 - Basis Swaps - Dominion South		4,550,000	Mcf		—		—		—		(0.83	)		380
2017 - Basis Swaps - Texas Gas		14,600,000	Mcf		—		—		—		(0.13	)		(602	)
2018 - Swaps		960,000	Mcf		—		—		—		3.60			573
2018 - Swaptions		-	Mcf		—		—		—		—			(164	)
2018 - Three-Way Collars		8,775,000	Mcf		2.30		2.89		3.58		—			(297	)
2018 - Calls		5,810,000	Mcf		—		—		3.97		—			(365	)
2018 - Basis Swaps - Dominion South		6,400,000	Mcf		—		—		—		(0.83	)		380
2018 - Basis Swaps - Texas Gas		14,600,000	Mcf		—		—		—		(0.13	)		(602	)
2019 - Basis Swaps - Dominion South		7,300,000	Mcf		—		—		—		(0.83	)		380
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.83	)		380
		116,955,000	Mcf										$	(1,015	)
NGLs
2016 - C3+ NGL Swaps		357,000	Bbls		—		—		—		26.22		$	(396	)
2016 - Ethane Swaps		165,000	Bbls		—		—		—		8.49			(106	)
2017 - C3+ NGL Swaps		468,000	Bbls		—		—		—		19.98			(2,455	)
2017 - Ethane Swaps		540,000	Bbls		—		—		—		10.13			(319	)
		1,530,000	Bbls										$	(3,276	)
Refined Product (Heating Oil)
2016 - Swaps		3,000	Bbls	$	—	$	—	$	—	$	84.00		$	(57	)
		3,000	Bbls										$	(57	)

19

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, 2016 and December 31, 2015 is summarized below:

	September 30,			December 31,
($ in Thousands)	2016			2015
Short-Term Derivative Assets:
Crude Oil—Collars	$	—		$	1,078
Crude Oil—Deferred Put Spread		—			852
Crude Oil—Three-Way Collars		—			577
NGL—Swaps		560			10,250
Natural Gas—Swaps		924			9,010
Natural Gas—Cap Swaps		227			1,977
Natural Gas—Basis Swaps		1,532			70
Natural Gas—Three-Way Collars		1,386			6,183
Natural Gas—Collars		—			1,728
Natural Gas—Swaption		46			798
Natural Gas—Call		2			—
Natural Gas—Put Spread		418			1,737
Contingent Consideration - Sale of Illinois Basin		366			—
Total Short-Term Derivative Assets	$	5,461		$	34,260
Long-Term Derivative Assets:
NGL—Swaps	$	33		$	344
Natural Gas—Cap Swaps		—			2,294
Natural Gas—Swaps		716			1,593
Natural Gas—Basis Swaps		1,236			195
Natural Gas—Three-Way Collars		582			5,108
Contingent Consideration - Sale of Illinois Basin		800			—
Total Long-Term Derivative Assets	$	3,367		$	9,534
Total Derivative Assets	$	8,828		$	43,794
Short-Term Derivative Liabilities:
Crude Oil—Three-Way Collars		(328	)		—
Crude Oil—Collars		(149	)		—
Crude Oil—Deferred Put Spread		(162	)		—
NGL—Swaps		(3,162	)		—
Refined Product—Swaps		(57	)		(376	)
Natural Gas—Three-Way Collars		(531	)		(31	)
Natural Gas—Collars		(418	)		—
Natural Gas—Basis Swaps		(451	)		(1,585	)
Natural Gas—Put Spread		(77	)		—
Natural Gas—Call		(706	)		—
Natural Gas—Swaption		(280	)		(202	)
Natural Gas—Swaps		(1,514	)		(292	)
Natural Gas—Cap Swaps		(1,459	)		—
Total Short - Term Derivative Liabilities	$	(9,294	)	$	(2,486	)
Long-Term Derivative Liabilities:
NGL—Swaps		(707	)		—
Natural Gas—Swaps		(22	)		—
Natural Gas—Swaption		(322	)		(297	)
Natural Gas—Basis Swaps		(752	)		(4,186	)
Natural Gas—Collars		(38	)		—
Natural Gas—Call		(600	)		(989	)
Natural Gas—Cap Swaps		(365	)		—
Natural Gas—Three-Way Collars		(548	)		(84	)
Total Long-Term Derivative Liabilities	$	(3,354	)	$	(5,556	)
Total Derivative Liabilities	$	(12,648	)	$	(8,042	)

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—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date.

20

Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. 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 and other like derivative contracts, 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—Unobservable inputs that are supported by little or no market activity. 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, 2016 and December 31, 2015, 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, 2016 and December 31, 2015, 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, 2016 and December 31, 2015 are included in the table below.

	As of September 30, 2016
	Range (price per Mcf)	Weighted Average (price per Mcf)			Fair Value (in thousands)
Natural Gas Basis Differential Forward Curve - Dominion South	($0.36) - ($1.80)	$	(0.82	)	$	2,768
Natural Gas Basis Differential Forward Curve - Texas Gas	($0.04) - ($0.10)	$	(0.08	)	$	(1,204	)
	As of December 31, 2015
	Range (price per Mcf)	Weighted Average (price per Mcf)			Fair Value (in thousands)
Natural Gas Basis Differential Forward Curve - Dominion South	($0.27) - ($1.08)	$	(0.74	)	$	(5,468	)
Natural Gas Basis Differential Forward Curve - Texas Gas	($0.05) - ($0.17)	$	(0.12	)	$	(38	)

The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the three and nine months ended September 30, 2016 and for the year ended December 31, 2015, 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:

				Fair Value Measurements at September 30, 2016 Using:
($ in Thousands)	Total Carrying Value as of September 30, 2016			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(3,820	)	$	—	$	(5,384	)	$	1,564
				Fair Value Measurements at December 31, 2015 Using:
($ in Thousands)	Total Carrying Value as of December 31, 2015			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	35,752		$	—	$	41,258		$	(5,506	)

Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our

21

credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations.

The value of our oil derivatives are comprised of three-way collar, call protected 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 values attributable to our oil derivatives as of September 30, 2016 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 swap, collars, swaption, three way collar, basis swap, cap swap, call and put spread 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, 2016 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, 2016 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, 2016 and 2015:

	Nine Months Ended September 30,
($ in Thousands)	2016			2015
Beginning Balance of Level 3	$	(5,506	)	$	1,341
Changes in Fair Value		7,249			371
Purchases		—			—
Settlements Paid (Received)		(179	)		(3,821	)
Ending Balance of Level 3	$	1,564		$	(2,109	)

Changes in fair value on our Level 3 commodity derivative contracts outstanding for the nine months ended September 30, 2016 and 2015, resulted in an increase of approximately $7.2 million and an increase of approximately $0.4 million, respectively. These amounts have been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.  

Future Abandonment Cost

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

Financial Instruments Not Recorded at Fair Value

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

	September 30, 2016				December 31, 2015
($ in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior Notes, Net of Issuance Costs and Deferred Gain on Debt Exchanges	$	633,322	$	169,686	$	663,089	$	137,402
Secured Line of Credit, Net of Issuance Costs		125,396		125,396		109,396		109,396
Capital Leases and Other Obligations		866		3,677		419		411
Total	$	759,584	$	298,759	$	772,904	$	247,209

22

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.

Other Fair Value Measurements

During the nine months ended September 30, 2016, we recorded an other than temporary impairment of $45.3 million related to proved and unproved properties. We utilize quoted futures prices and other observable market data in determining the fair value. The inputs used in determining fair value as a part of the impairment expense calculation are considered to be Level 2 within the fair value hierarchy. For additional information on our impairment expense, see Note 15, Impairment Expense, to our Consolidated Financial Statements.

9. INCOME TAXES

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.

Income tax included in continuing operations was as follows:

	Three Months Ended September 30,						Nine Months Ended   September 30,
($ in Thousands)	2016			2015			2016			2015
Income Tax Benefit	$	8,106		$	-		$	5,785		$	-
Effective Tax Rate		33.0	%		0.0	%		4.5	%		0.0	%

Management estimates the annual effective income tax rate quarterly, based on current annual forecasted results. Items unrelated to current year ordinary income are recognized entirely in the period identified as a discrete item of tax. The quarterly income tax provision is comprised of tax on ordinary income provided at the most recent estimated annual effective tax rate, adjusted for the tax effect of these discrete items. The Company accounts for the tax effects of discontinued operations as a discrete item and therefore recognizes the full tax effects of discontinued operations in the same period that the pretax income or loss from discontinued operations is recognized. As a result of having a full valuation allowance on deferred taxes on the Company’s entire operations, this approach results in a tax benefit being recorded in continuing operations to offset the tax charge on the gain recorded in discontinued operations.

23

For the nine months ended September 30, 2016, the estimated annual effective tax rate applied to ordinary losses from continuing operations was 5.1% before consideration of discrete items.  The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of having full valuation allowances recorded against our deferred tax assets coupled with recognizing tax benefits in continuing operations for the effect of taxable income generated by our discontinued operations. To a lesser extent, the annual effective rate is also influenced by alternative minimum tax with no corresponding deferred tax benefit due to the full valuation allowance, and state taxes in certain tax paying jurisdictions.  The Company’s alternative minimum tax expected to be due for 2016 is driven primarily by cancellation of debt income of $543.2 million related to the Senior Note exchanges discussed in Note 7, Long-Term Debt, to our Consolidated Financial Statements. The Company recorded a benefit for income taxes from continuing operations of $5.8 million, or 4.5%, inclusive of certain insignificant discrete items, for federal and state income taxes for the nine months ended September 30, 2016.

For the nine months ended September 30, 2015, the estimated annual effective tax rate applied to ordinary losses from continuing operations was 0.0% due to the recording of full valuations allowances against the tax benefits generated by pretax losses, resulting in recognition of no tax benefit for the period.  The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of having full valuation allowances recorded against our deferred tax assets.

Income tax payments made during the nine months ended September 30, 2016 and 2015 were negligible.  Tax refunds received during the nine months ended September 30, 2016 were negligible, and refunds of approximately $0.5 million were received during the nine months ended September 30, 2015.

10. CAPITAL STOCK

Common Stock

On May 27, 2016, the Company’s common shareholders approved an increase in the number of authorized shares from 100,000,000 to 200,000,000 common shares.  As of September 30, 2016, we have authorized capital stock of 200,000,000 shares of common stock and 100,000 shares of preferred stock. As of September 30, 2016 and December 31, 2015, shares of common stock issued and outstanding totaled 95,886,983 and 55,741,229, respectively.  During the nine-month period ending September 30, 2016, we issued approximately 8.4 million shares of our common stock in conjunction with the Exchange completed on March 31, 2016, and approximately 22.7 million shares of our common stock in debt-to-equity exchanges with certain holders of our Senior Notes.  See Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information regarding our debt and equity exchanges.

Preferred Stock

As of September 30, 2016 and December 31, 2015, shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”) issued and outstanding totaled 4,087 and 16,100, respectively. During the nine months ended September 30, 2016, 12,013 shares of Series A Preferred Stock were converted into approximately 9.0 million shares of common stock pursuant to the terms of the Series A Preferred Stock, and through negotiated exchanges with certain holders of the Series A Preferred Shares. See Note 13, Earnings Per Common Share, to our Consolidated Financial Statements, for additional information regarding the effect of the preferred stock conversions on Net Loss Attributable to Common Shareholders.

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 February 15, May 15, August 15 and November 15 of each year.

We pay cumulative dividends, when and if declared, in cash, stock or a combination thereof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. Dividends that are not declared and paid in accordance with the quarterly schedule will accumulate from the most recent date upon which dividends were paid but will not bear interest. In February 2016, we suspended our quarterly dividend payment. No dividend has been declared by our board of directors in 2016. As of September 30, 2016 accumulated dividends in arrears totaled $4.4 million.  While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulated dividends are added to our Net Loss in the determination of Loss Attributable to Common Shareholders and related loss per share calculations.

In 2015, we paid quarterly cash dividends of $150.00 per share for the periods of November 15, 2014 to February 15, 2015, February 15, 2015 to May 15, 2015, May 15, 2015 to August 15, 2015, and August 15, 2015 to November 15, 2015, respectively, each in the aggregate amount of $2.4 million. If we do not pay dividends for an aggregate of six quarterly periods, the holders of the shares of Series A Preferred Stock will have the right to elect two additional directors to serve on our board of directors.

24

11. EMPLOYEE BENEFIT AND EQUITY PLANS

Equity Plans

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.

Stock Options

During the nine-month period ended September 30, 2016, we issued 888,922 options to purchase shares of our common stock to 34 employees.  During the nine-month period ended September 30, 2015, we issued 80,000 options to purchase shares of our common stock to 3 employees.  Stock-based compensation expense from continuing operations relating to stock options outstanding for each of the three and nine months ended September 30, 2016 was $0.1 million and $0.2 million, respectively.Stock-based compensation relating to stock options outstanding for the three and nine month periods ended September 30, 2015 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. There were no stock options exercised for the nine months ended September 30, 2016. There was no tax benefit related to stock option exercises for each of the nine-month periods ended September 30, 2016 and 2015.

A summary of the status of our issued and outstanding stock options as of September 30, 2016 is as follows:

		Outstanding				Exercisable
Exercise Price		Number Outstanding at September 30, 2016		Weighted-Average Exercise Price		Number Exercisable at September 30, 2016		Weighted-Average Exercise Price
$	0.97		37,500	$	0.97		—	$	0.97
$	1.69		753,428	$	1.69		—	$	1.69
$	4.05		40,000	$	4.05		—	$	4.05
$	4.90		40,000	$	4.90		3,333	$	4.90
$	5.04		46,041	$	5.04		46,041	$	5.04
$	9.50		75,000	$	9.50		75,000	$	9.50
$	9.99		129,583	$	9.99		129,583	$	9.99
$	10.42		29,548	$	10.42		29,548	$	10.42
$	22.34		30,000	$	22.34		30,000	$	22.34
			1,181,100	$	4.14		313,505	$	10.31

The weighted average remaining contractual term for options outstanding at September 30, 2016 was 5.0 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at September 30, 2016 was 1.4 years and there was no aggregate intrinsic value.  As of September 30, 2016, unrecognized compensation expense related to stock options was $0.4 million.  

Restricted Stock Awards

During the nine-month period ended September 30, 2016, the Compensation Committee approved the issuance of an aggregate of 567,205 shares of restricted common stock to 51 employees. During the nine-month period ended September 30, 2015, the Compensation Committee approved the issuance of an aggregate of 1,361,497 shares of restricted stock to 127 employees, one director and one non-employee contractor. Certain of our outstanding restricted stock awards granted in 2015 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.

25

The weighted average fair value of the TSR awards granted as of December 31, 2015 was $2.56 per share.There have been no TSR awards granted in 2016.  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:

	Year Ended December 31, 2015
Expected Dividend Yield		0.0	%
Risk-Free Interest Rate		1.0	%
Expected Volatility – Rex Energy		58.6	%
Expected Volatility – Peer Group	29.8%-85.0%
Market Index		35.6	%
Expected Life	Three Years

Compensation expense from restricted stock awards associated with our continuing operations totaled $0.9 million and $1.8 million for the three and nine-month periods ended September 30, 2016, respectively, and negligible and $4.4 million for the three and nine-month periods ended September 30, 2015, respectively.During the first quarter of 2016, 235,573 performance stock awards were forfeited due to not meeting specified targets, which resulted in a one-time reduction to expense of approximately $1.5 million. During the first quarter of 2015, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2015. This waiver resulted in the vesting of 189,872 restricted stock awards with associated expense of approximately $2.5 million. As of September 30, 2016, total unrecognized compensation cost related to restricted common stock grants was approximately $2.0 million, which will be recognized over a weighted average period of 1.2 years.

A summary of the restricted stock activity for the nine months ended September 30, 2016 is as follows:

	Number of Shares			Weighted-Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2015		2,479,408		$	6.27
Awards		567,205			1.40
Forfeitures		(591,437	)		6.78
Vested		(743,487	)		5.33
Restricted stock awards, as of September 30, 2016		1,711,689		$	4.89

12. COMMITMENTS AND CONTINGENCIES

Legal Reserves

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.

Other than as set forth below, 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, 2015.

In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them on behalf of the

26

Company. The plaintiffs seek a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. We filed affirmative defenses and preliminary objections to the plaintiff’s claims, and the parties each made various responsive filings throughout the first quarter of 2012. In May 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal during the second half of 2012. In May 2013, the Superior Court reversed the decision of the Common Pleas Court and remanded the case for further proceedings.

In July 2012, while the Cardinale case was in the midst of the appeals process, counsel for the plaintiffs in the Cardinale case filed two additional lawsuits against us in the Court of Common Pleas of Clearfield County, Pennsylvania: one a proposed class action lawsuit with a different named plaintiff (the “Billotte case”) and another on behalf of a group of individually named plaintiffs (the “Meeker case”). The complaint for the Billotte case contained the same claims as those set forth in the Cardinale case. The Meeker case is not a class action, but the claims are similar to those in Cardinale and the plaintiffs would be included in a class under Cardinale and Billotte if one were certified. These two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case and the pendency of the appeal. Proceedings in both the Billotte and Meeker cases were stayed pending the outcome of the appeal in the Cardinale case. When the Cardinale case was remanded, we agreed to consolidate the Billotte and Cardinale cases; the cases have proceeded as Cardinale. The Meeker case remains stayed, and has not been consolidated.

In June 2015, the trial court conducted a hearing on plaintiff’s motion for certification of a class in the Cardinale case.  In July 2015, the trial court denied plaintiffs’ motion for class certification.  Plaintiffs appealed the denial of class certification in September 2015.  In June 2016, we and the plaintiffs each presented our arguments on the appeal before a three-judge panel of the Pennsylvania Superior Court.  To date, the court has not ruled on the appeal.  We expect to receive the court’s ruling on the appeal in the fourth quarter of 2016.

We continue to vigorously defend against each of these claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.

Illinois Basin EPA Consent Decree

In September 2006, the United States Department of Justice (“DOJ”), the United States Environmental Protection Agency (“EPA”) and the State of Illinois initiated an enforcement action against us seeking mandatory injunctive relief and potential civil penalties based on allegations that we (and various predecessor companies) were violating the Clean Air Act in connection with the release of hydrogen sulfide gas and volatile organic compounds (“VOC’s”) in the course of our oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. In June 2007, we entered a consent decree to resolve the enforcement action. The consent decree required us to take certain remedial actions to reduce hydrogen sulfide and VOC emissions and monitor the same. The

consent decree did not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.

In 2010, the EPA, DOJ and Illinois EPA approved revisions we proposed to a Directed Inspection and Maintenance Plan, which had been previously implemented by us pursuant to the terms of the consent decree. In 2014, in consultation with the EPA, DOJ and Illinois EPA, we implemented additional measures under the Directed Inspection and Maintenance Plan to reflect changes in hydrogen sulfide control monitoring and procedures. The consent decree required us to submit quarterly reports and to annually reassess the Directed Inspection and Maintenance Plan.  There were no material changes to the Directed Inspection and Maintenance Plan in 2015 or through September 30, 2016, and we were compliant with all reporting requirements for those periods.

In August 2016, we sold all of our assets in the Illinois Basin to Campbell (see Note 3 Discontinued Operations/Assets Held for Sale), including all assets that were subject to and covered under the consent decree.  We notified the EPA, DOJ and Illinois EPA of the transaction as required by the consent decree and prepared and submitted all necessary reports for the three month-period ending September 30, 2016. As the consent decree relates specifically to a subset of the assets included in the sale of the Illinois Basin assets, all future responsibility for compliance with the terms of the consent decree transferred to the new owner upon closing of the sale transaction.

Environmental

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

27

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, 2016, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

As of September 30, 2016, we have posted $42.9 million in various letters of credit to secure our drilling and related operations.

Lease Commitments

As of September 30, 2016, 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, 2016, was approximately $0.3 million and $0.9 million, respectively, and $0.3 million and $0.7 million for the three and nine months ended September 30, 2015, respectively. Lease commitments by year for each of the next five years are presented in the table below:

($ in Thousands)
2016	$	251
2017		997
2018		565
2019		563
2020		422
Thereafter		—
Total	$	2,798

Capacity Reservation

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 utilize the plants to process quantities of gas sufficient to meet specified volume commitments, we may be obligated to pay approximately $3.8 million in 2016, $16.7 million in 2017, $16.7 million in 2018, $16.7 million in 2019, $16.7 million in 2020 and $98.6 million thereafter, assuming our average net revenue interest in the region of approximately 53%. Charges incurred for unutilized processing capacity with MarkWest during the three and nine-month periods ended September 30, 2016 were $0.8 million and $2.2 million, respectively, and negligible and $0.4 million for the three and nine-month periods ended September 30, 2015, respectively.

Operational Commitments

We have contracted drilling rig services on one rig to support our Appalachian Basin operations. The minimum cost to retain this rig would require gross payments of approximately $0.6 million in 2016, $2.3 million in 2017 and $0.5 million in 2018, which would be partially offset by other working interest owners, which vary from well to well. During the first quarter of 2015, we terminated two rig contracts earlier than their original term. To satisfy the early release, we incurred approximately $4.8 million in early termination fees, which were classified as Other Operating Expense in our Consolidated Statement of Operations as of September 30, 2015. Approximately $2.3 million of this amount was paid in January 2015 and $2.5 million in January 2016. We also have agreements for contracted completion services in the Appalachian Basin. The minimum gross cost to retain the completion services is approximately $0.4 million in 2016, which would be partially offset by other working interest owners, which vary from well to well.

Natural Gas Gathering, Processing and Sales Agreements

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 natural gas, NGLs and condensate. 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 $408.2 million through 2029.

28

For the three and nine months ended September 30, 2016 and 2015, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $22.9 million and $66.2 million in 2016, respectively, and $20.9 million and $60.3 million in 2015, 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. During the three and nine months ended September 30, 2016 and 2015, we incurred approximately $0.7 million and $1.7 million in 2016, respectively, and $0.7 million and $2.8 million in 2015, respectively, in fees related to unutilized capacity commitments. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:

($ in Thousands)
2016	$	8,994
2017		43,929
2018		47,398
2019		48,447
2020		47,142
Thereafter		533,582
Total	$	729,492

During the three and nine months ended September 30, 2016, we recorded a liability of approximately $8.3 million for our future obligations stipulated in a firm transportation contract related to an area west of our core assets in Butler County, Pennsylvania.  During the third quarter of 2016, we elected to cease all future development activities in the area associated with the contract. The liability recorded represents the present value of our full obligation under the contract, resulting in expense of approximately $8.3 million to Other Operating Expense in our Consolidated Statement of Operations.

Pennsylvania Impact Fee

In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee is 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:

	<$2.25(a)		$2.26 - $2.99(a)		$3.00 - $4.99(a)		$5.00 - $5.99(a)		>$5.99(a)
Year One	$	40,200	$	45,300	$	50,300	$	55,300	$	60,400
Year Two	$	30,200	$	35,200	$	40,200	$	45,300	$	55,300
Year Three	$	25,200	$	30,200	$	30,200	$	40,200	$	50,300
Year 4 – 10	$	10,100	$	15,100	$	20,100	$	20,100	$	20,100
Year 11 – 15	$	5,000	$	5,000	$	10,100	$	10,100	$	10,100

^(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 are due on April 1 of each year. For the three and nine months ended September 30, 2016 and 2015, we recorded expense of approximately $0.8 million and $2.1 million in 2016, respectively, and $0.8 million and $2.3 million in 2015, respectively.We record expenses related to the impact fees as Production and Lease Operating Expense. As of September 30, 2016, approximately $2.1 million was accrued for 2016 impact fees.

29

13. EARNINGS PER COMMON SHARE

Basic income (loss) 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 and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For each of the three and nine months ended September 30, 2016 and 2015, we excluded stock options to purchase 1.2 million shares and 0.5 million shares of our common stock, respectively, due to our Net Loss from Continuing Operations. For the three and nine months ended September 30, 2016, we excluded performance-based restricted stock of 0.7 million shares and 0.6 million shares, respectively, due to performance metrics that have not yet been attained. For the three and nine months ended September 30, 2015, we excluded performance-based restricted stock of 1.1 million shares due to performance metrics that have not yet been attained (for additional information on our non-cash compensation plans, see Note 11, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). We utilize the if-converted method for calculating the impact of our 6.0% Convertible Perpetual Preferred Stock on diluted earnings per share. Under the if-converted method, convertible preferred stock is assumed as converted to common shares for the weighted average period outstanding. For each of the three and nine-month periods ended September 30, 2016 and September 30, 2015, we excluded the assumed conversion of preferred stock equating to approximately 2.3 million shares and 8.9 million shares, respectively, due to our Net Loss from Continuing Operations. We included in Net Income (Loss) Attributable to Common Shareholders the effect of the preferred share to common share conversions completed during the three and nine months ended September 30, 2016. The conversions completed during these periods resulted in an increase in Net Income (decrease in Net Loss) Attributable to Common Shareholders of approximately $72.3 million, representing the carrying value of the preferred shares converted in excess of the fair value of the common shares issued in the conversions. 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:	2016			2015			2016			2015
Net Loss From Continuing Operations	$	(16,477	)	$	(88,891	)	$	(122,040	)	$	(255,226	)
Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests		21,892			(5,784	)		12,719			(10,015	)
Less: Preferred Stock Dividends		(613	)		(2,415	)		(4,441	)		(7,245	)
Effect of Preferred Stock Conversions		—			—			72,316			—
Net Income (Loss) Attributable to Common Shareholders	$	4,802		$	(97,090	)	$	(41,446	)	$	(272,486	)
Denominator:
Weighted Average Common Shares Outstanding - Basic		90,803			53,936			73,098			53,748
Effect of Dilutive Securities:
Employee Stock Options		—			—			—			—
Employee Performance-Based Restricted Stock Awards		—			—			—			—
Effect of Assumed Conversions of Preferred Stock		—			—			—			—
Weighted Average Common Shares Outstanding - Diluted		90,803			53,936			73,098			53,748
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Loss From Continuing Operations	$	(0.19	)	$	(1.69	)	$	(0.74	)	$	(4.88	)
— Net Income (Loss) From Discontinued Operations		0.24			(0.11	)		0.17			(0.19	)
— Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	0.05		$	(1.80	)	$	(0.57	)	$	(5.07	)
Diluted — Net Loss From Continuing Operations	$	(0.19	)	$	(1.69	)	$	(0.74	)	$	(4.88	)
— Net Income (Loss) From Discontinued Operations		0.24			(0.11	)		0.17			(0.19	)
— Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	0.05		$	(1.80	)	$	(0.57	)	$	(5.07	)

14. EQUITY METHOD INVESTMENTS

RW Gathering, LLC

We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our natural gas operations. During the second quarter of 2015 we incurred a 100% impairment charge of $17.5 million related to RW Gathering. We did not make any capital contributions to RW Gathering during the first nine months of 2016 and 2015.  RW Gathering recorded net losses from continuing operations of $0.5 million and $1.5 million during the three and nine-month periods ended September 30, 2016, respectively, as compared to losses of $0.5 million and $1.5 million for the comparable periods in 2015. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Historically, we recorded our share of the net losses on the Statements of Operations as Loss on Equity Method Investments. As of June 30, 2015, we discontinued applying the equity method of accounting for our share of net losses due to our investment being reduced to zero.

During the three and nine-month periods ended September 30, 2016 we incurred approximately $0.2 million and $0.5 million, respectively, as compared to $0.2 million and $0.5 million for the three and nine-month periods ended September 30, 2015, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation

30

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, 2016 and December 31, 2015, there were no receivables or payables due between RW Gathering and us.

15. IMPAIRMENT EXPENSE

For the three and nine months ended September 30, 2016, impairment expenses incurred were approximately $9.6 million and $45.3 million, respectively, and impairment expenses incurred for the three and nine-month periods ended September 30, 2015 were approximately $85.2 million and $209.9 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first nine months of 2016 included approximately $42.1 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio.  Impairments of proved properties in our Butler County operations totaled approximately $1.1 million during the first nine months of 2016. The impairments were identified through an analysis of market conditions and future development plans that were in existence as of each period end, related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets and future development plans.  Our estimates of future cash flows attributable to our oil and gas properties could decline if commodity prices decline, which may result in our incurrence of additional impairment expense. As of September 30, 2016, we continued to carry the costs of undeveloped properties of approximately $223.8 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale and for which we have development, trade or lease extension plans.

The expense incurred during the first nine months of 2015 included proved properties of approximately $153.9 million attributable to unconventional assets in the Appalachian Basin. In addition to the proved properties, we also incurred approximately $38.5 million in impairment related to unproved properties, the majority of which were located in our non-operated dry gas regions of Clearfield and Westmoreland Counties, Pennsylvania, and $17.5 million related to our equity method investment in RW Gathering. The remaining 2015 impairments were primarily related to acreage expirations and pipelines in non-core areas.

16. EXPLORATION EXPENSE

For the three and nine months ended September 30, 2016, we incurred approximately $0.2 million and $2.0 million, respectively, in exploration expenses as compared to $0.6 million and $1.8 million in exploration expenses for the same periods in 2015, respectively.   Approximately $1.0 million of the expense incurred in 2016 was due to geological and geophysical type expenditures and the remaining $1.0 million was due to costs associated with exploratory wells that were abandoned at various stages resulting in dry hole expense and delay rentals. Approximately $0.6 million of the expense incurred in 2015 was due to geological and geophysical type expenditures.  An additional $1.0 million of expense was incurred through the payment of delay rentals, and the remaining 2015 expense of $0.2 million was due to costs associated with exploratory wells that were abandoned at various stages resulting in dry hole expense.  

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

As of September 30, 2016, we had an aggregate of $602.1 million of outstanding Senior Notes, as shown in Note 7, 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, 2016:

• Rex Energy I, LLC

• Rex Energy Operating Corporation

• Rex Energy IV, LLC

• PennTex Resources Illinois, Inc.

• R.E. Gas Development, LLC

The non-guarantor subsidiaries include certain consolidated subsidiaries, including 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, 2016, 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.

31

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, 2016 and December 31, 2015, the condensed consolidating statements of operations for each of the three and nine-month periods ended September 30, 2016 and 2015, and the condensed consolidating statements of cash flows for each of the nine-month periods ended September 30, 2016 and 2015.

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF SEPTEMBER 30, 2016

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)				Eliminations				Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	2,521		$	—			$	3			$	—			$	2,524
Accounts Receivable		14,902			—				6,753				—				21,655
Taxes Receivable		—			—				211				—				211
Short-Term Derivative Instruments		5,095			—				366				—				5,461
Inventory, Prepaid Expenses and Other		1,041			—				38				—				1,079
Assets Held for Sale		—			—				—				—				—
Total Current Assets		23,559			—				7,371				—				30,930
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,020,993			—				—				—				1,020,993
Unevaluated Oil and Gas Properties		223,791			—				—				—				223,791
Other Property and Equipment		21,449			—				—				—				21,449
Wells and Facilities in Progress		66,614			—				—				—				66,614
Pipelines		15,186			—				—				—				15,186
Total Property and Equipment		1,348,033			—				—				—				1,348,033
Less: Accumulated Depreciation, Depletion and Amortization		(459,549	)		—				—				—				(459,549	)
Net Property and Equipment		888,484			—				—				—				888,484
Other Assets		2,492			—				—				—				2,492
Intercompany Receivables		—			—				1,051,712				(1,051,712	)			—
Investment in Subsidiaries – Net		(2,388	)		—				(127,974	)			130,362				—
Long-Term Derivative Instruments		2,567			—				800				—				3,367
Total Assets	$	914,714		$	—			$	931,909			$	(921,350	)		$	925,273
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	29,464		$	—			$	—			$	—			$	29,464
Current Maturities of Long-Term Debt		201			—				—				—				201
Accrued Liabilities		23,405			421				5,793				—				29,619
Short-Term Derivative Instruments		9,294			—				—				—				9,294
Liabilities Related to Assets Held for Sale		631			—				—				—				631
Total Current Liabilities		62,995			421				5,793				—				69,209
Long-Term Derivative Instruments		3,354			—				—				—				3,354
Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs		666			—				125,395				—				126,061
Senior Notes, Net of Issuance Costs		—			—				633,322				—				633,322
Premium on Senior Notes – Net		—			—				134				—				134
Other Deposits and Liabilities		9,617			—				—				—				9,617
Future Abandonment Cost		7,438			—				—				—				7,438
Intercompany Payables		1,048,032			3,680				—				(1,051,712	)			—
Total Liabilities		1,132,102			4,101				764,644				(1,051,712	)			849,135
Stockholders’ Equity
Preferred Stock		—			—				1				—				1
Common Stock		—			—				94				—				94
Additional Paid-In Capital		177,144			—				649,103				(177,144	)			649,103
Accumulated Earnings (Deficit)		(394,532	)		(4,101	)			(481,933	)			307,506				(573,060	)
Total Stockholders’ Equity		(217,388	)		(4,101	)			167,265				130,362				76,138
Total Liabilities and Stockholders’ Equity	$	914,714		$	—			$	931,909			$	(921,350	)		$	925,273

32

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2016

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	34,034		$	—	$	—		$	—		$	34,034
Other Revenue		5			—		—			—			5
TOTAL OPERATING REVENUE		34,039			—		—			—			34,039
OPERATING EXPENSES
Production and Lease Operating Expense		26,333			—		—			—			26,333
General and Administrative Expense		4,114			—		1,002			—			5,116
Loss on Disposal of Assets		10			—		—			—			10
Impairment Expense		9,563			—		—			—			9,563
Exploration Expense		216			—		—			—			216
Depreciation, Depletion, Amortization and Accretion		15,109			—		—			—			15,109
Other Operating Expense		9,899			—		—			—			9,899
TOTAL OPERATING EXPENSES		65,244			—		1,002			—			66,246
LOSS FROM OPERATIONS		(31,205	)		—		(1,002	)		—			(32,207	)
OTHER INCOME (EXPENSE)
Interest Expense		(305	)		—		(9,341	)		—			(9,646	)
Gain on Derivatives, Net		16,866			—		—			—			16,866
Other Income		16			���		—			—			16
Debt Exchange Expense		—			—		(35	)		—			(35	)
Gain on Extinguishment of Debt		—			—		423			—			423
Income From Equity in Consolidated Subsidiaries		—			—		12,087			(12,087	)		—
TOTAL OTHER INCOME (EXPENSE)		16,577			—		3,134			(12,087	)		7,624
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME    TAX		(14,628	)		—		2,132			(12,087	)		(24,583	)
Income Tax Expense		4,823			—		3,283			—			8,106
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(9,805	)		—		5,415			(12,087	)		(16,477	)
Income From Discontinued Operations, Net of Income Taxes		21,892			—		—			—			21,892
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY		12,087			—		5,415			(12,087	)		5,415
Preferred Stock Dividends		—			—		(613	)		—			(613	)
Effect of Preferred Stock Conversions		—			—		—			—			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	12,087		$	—	$	4,802		$	(12,087	)	$	4,802

33

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2016

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	90,978		$	—		$	—		$	—	$	90,978
Other Revenue		12			—			—			—		12
TOTAL OPERATING REVENUE		90,990			—			—			—		90,990
OPERATING EXPENSES
Production and Lease Operating Expense		76,004			1			—			—		76,005
General and Administrative Expense		13,193			—			2,044			—		15,237
Gain on Disposal of Assets		(4,285	)		—			—			—		(4,285	)
Impairment Expense		45,344			—			—			—		45,344
Exploration Expense		1,953			1			—			—		1,954
Depreciation, Depletion, Amortization and Accretion		46,358			13			—			—		46,371
Other Operating Expense		10,930			—			—			—		10,930
TOTAL OPERATING EXPENSES		189,497			15			2,044			—		191,556
LOSS FROM OPERATIONS		(98,507	)		(15	)		(2,044	)		—		(100,566	)
OTHER INCOME (EXPENSE)
Interest Expense		(844	)		—			(33,271	)		—		(34,115	)
Loss on Derivatives, Net		(8,254	)		—			—			—		(8,254	)
Other Income		28			—			—			—		28
Debt Exchange Expense		—			—			(9,048	)		—		(9,048	)
Gain on Extinguishment of Debt		—			—			24,130			—		24,130
Income (Loss) From Equity in Consolidated Subsidiaries		79			(79	)		(90,008	)		90,008		—
TOTAL OTHER INCOME (EXPENSE)		(8,991	)		(79	)		(108,197	)		90,008		(27,259	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME    TAX		(107,498	)		(94	)		(110,241	)		90,008		(127,825	)
Income Tax Benefit		4,865			—			920			—		5,785
INCOME (LOSS) FROM CONTINUING OPERATIONS		(102,633	)		(94	)		(109,321	)		90,008		(122,040	)
Income (Loss) From Discontinued Operations, Net of Income Tax		12,786			(67	)		—			—		12,719
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(89,847	)	$	(161	)	$	(109,321	)	$	90,008	$	(109,321	)
Preferred Stock Dividends		—			—			(4,441	)		—		(4,441	)
Effect of Preferred Stock Conversions		—			—			72,316			—		72,316
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(89,847	)	$	(161	)	$	(41,446	)	$	90,008	$	(41,446	)

34

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2016

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(89,847	)	$	(161	)	$	(109,321	)	$	90,008		$	(109,321	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating    Activities
Non-Cash Expenses (Income)		(170	)		—			17,313			—			17,143
Depreciation, Depletion, Amortization and Accretion		51,456			15			—			—			51,471
Loss on Derivatives		8,254			—			—			—			8,254
Cash Settlements of Derivatives		32,485			—			—			—			32,485
Dry Hole Expense		848			24			—			—			872
Gain (Loss) on Disposal of Assets		(34,837	)		17			—			—			(34,820	)
Gain on Extinguishment Debt		—			—			(24,213	)		—			(24,213	)
Impairment Expense		48,887			—			48,887			(48,887	)		48,887
Changes in operating assets and liabilities
Accounts Receivable		(21,121	)		(346	)		18,887			—			(2,580	)
Inventory, Prepaid Expenses and Other Assets		2,387			—			(13	)		—			2,374
Accounts Payable and Accrued Liabilities		(3,156	)		—			(4,625	)		—			(7,781	)
Other Assets and Liabilities		(1,219	)		(25	)		—			—			(1,244	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(6,033	)		(476	)		(53,085	)		41,121			(18,473	)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		3,060			121			37,940			(41,121	)		—
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		40,347			462			—			—			40,809
Proceeds from Joint Venture		19,461			—			—			—			19,461
Acquisitions of Undeveloped Acreage		(6,261	)		(41	)		—			—			(6,302	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(48,601	)		(39	)		—			—			(48,640	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		8,006			503			37,940			(41,121	)		5,328
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			—			55,400			—			55,400
Repayments of Long-Term Debt and Lines of Credit		—			—			(35,230	)		—			(35,230	)
Repayments of Loans and Other Long-Term Debt		(541	)		(27	)		—			—			(568	)
Debt Issuance Costs		—			—			(5,024	)		—			(5,024	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(541	)		(27	)		15,146			—			14,578
NET INCREASE IN CASH		1,432			—			1			—			1,433
CASH – BEGINNING		1,089			—			2			—			1,091
CASH - ENDING	$	2,521		$	—		$	3		$	—		$	2,524

35

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF DECEMBER 31, 2015

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,089		$	—	$	2		$	—		$	1,091
Accounts Receivable		17,225			—		49			—			17,274
Taxes Receivable		—			—		18			—			18
Short-Term Derivative Instruments		34,260			—		—			—			34,260
Inventory, Prepaid Expenses and Other		3,034			—		25			—			3,059
Assets Held for Sale		59,411			1,040		—			—			60,451
Total Current Assets		115,019			1,040		94			—			116,153
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		950,062			—		—			(6,970	)		943,092
Unevaluated Oil and Gas Properties		262,992			—		—			—			262,992
Other Property and Equipment		20,363			—		—			—			20,363
Wells and Facilities in Progress		141,370			—		—			(270	)		141,100
Pipelines		16,161			—		—			(2,137	)		14,024
Total Property and Equipment		1,390,948			—		—			(9,377	)		1,381,571
Less: Accumulated Depreciation, Depletion and Amortization		(441,346	)		—		—			3,518			(437,828	)
Net Property and Equipment		949,602			—		—			(5,859	)		943,743
Deferred Financing Costs and Other Assets—Net		2,501			—		—			—			2,501
Intercompany Receivables		—			—		1,070,548			(1,070,548	)		—
Investment in Subsidiaries – Net		(1,907	)		—		243,331			(241,424	)		—
Long-Term Derivative Instruments		9,534			—		—			—			9,534
Total Assets	$	1,074,749		$	1,040	$	1,313,973		$	(1,317,831	)	$	1,071,931
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	36,785		$	—	$	—		$	—		$	36,785
Current Maturities of Long-Term Debt		402			—		—			—			402
Accrued Liabilities		28,883			—		11,725			—			40,608
Short-Term Derivative Instruments		2,486			—		—			—			2,486
Liabilities Related to Assets Held for Sale		36,289			31		—			—			36,320
Total Current Liabilities		104,845			31		11,725			—			116,601
Long-Term Derivative Instruments		5,556			—		—			—			5,556
Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs		28			—		109,358			—			109,386
Senior Notes, Net of Issuance Costs		—			—		663,089			—			663,089
Premium on Senior Notes – Net		—			—		2,344			—			2,344
Other Deposits and Liabilities		3,156			—		—			—			3,156
Future Abandonment Cost		11,159			409		—			—			11,568
Intercompany Payables		1,070,096			452		—			(1,070,548	)		—
Total Liabilities		1,194,840			892		786,516			(1,070,548	)		911,700
Stockholders’ Equity
Preferred Stock		—			—		1			—			1
Common Stock		—			—		54			—			54
Additional Paid-In Capital		177,143			—		619,777			(173,057	)		623,863
Accumulated Earnings (Deficit)		(297,234	)		148		(92,375	)		(74,226	)		(463,687	)
Total Stockholders’ Equity		(120,091	)		148		527,457			(247,283	)		160,231
Total Liabilities and Stockholders’ Equity	$	1,074,749		$	1,040	$	1,313,973		$	(1,317,831	)	$	1,071,931

36

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2015  

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	29,648		$	—		$	—		$	—		$	29,648
Other Revenue		8			—			—			—			8
TOTAL OPERATING REVENUE		29,656			—			—			—			29,656
OPERATING EXPENSES
Production and Lease Operating Expense		24,259			—			—			—			24,259
General and Administrative Expense		4,577			—			(70	)		—			4,507
Gain on Disposal of Assets		(224	)		—			—			—			(224	)
Impairment Expense		86,223			—			—			(1,030	)		85,193
Exploration Expense		580			—			—			—			580
Depreciation, Depletion, Amortization and Accretion		21,105			—			—			(273	)		20,832
Other Operating Income		190			—			—			—			190
TOTAL OPERATING EXPENSES		136,710			—			(70	)		(1,303	)		135,337
INCOME (LOSS) FROM OPERATIONS		(107,054	)		—			70			1,303			(105,681	)
OTHER INCOME (EXPENSE)
Interest Expense		(51	)		—			(11,833	)		—			(11,884	)
Gain on Derivatives, Net		27,499			—			1,150			—			28,649
Other Income		25			—			—			—			25
Income (Loss) From Equity in Consolidated Subsidiaries		(1,063	)		1,063			(86,517	)		86,517			—
TOTAL OTHER INCOME (EXPENSE)		26,410			1,063			(97,200	)		86,517			16,790
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE    INCOME TAX		(80,644	)		1,063			(97,130	)		87,820			(88,891	)
Income Tax (Expense) Benefit		(2,453	)		—			2,453			—			—
INCOME (LOSS) FROM CONTINUING OPERATIONS		(83,097	)		1,063			(94,677	)		87,820			(88,891	)
Income (Loss) From Discontinued Operations, Net of Income Tax		(39,340	)		33,495			—			60			(5,785	)
Net Income (Loss)		(122,437	)		34,558			(94,677	)		87,880			(94,676	)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			(1	)		—			—			(1	)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(122,437	)	$	34,559		$	(94,677	)	$	87,880		$	(94,675	)
Preferred Stock Dividends		—			—			(2,415	)		—			(2,415	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(122,437	)	$	34,559		$	(97,092	)	$	87,880		$	(97,090	)

37

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2015  

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	111,344		$	—	$	—		$	—		$	111,344
Other Revenue		30			—		—			—			30
TOTAL OPERATING REVENUE		111,374			—		—			—			111,374
OPERATING EXPENSES
Production and Lease Operating Expense		71,646			—		—			—			71,646
General and Administrative Expense		15,378			—		4,875			—			20,253
Gain on Disposal of Assets		(533	)		—		—			—			(533	)
Impairment Expense		210,910			—		—			(1,030	)		209,880
Exploration Expense		1,779			—		—			(5	)		1,774
Depreciation, Depletion, Amortization and Accretion		68,141			—		—			(772	)		67,369
Other Operating Expense		5,328			—		—			—			5,328
TOTAL OPERATING EXPENSES		372,649			—		4,875			(1,807	)		375,717
INCOME (LOSS) FROM OPERATIONS		(261,275	)		—		(4,875	)		1,807			(264,343	)
OTHER INCOME (EXPENSE)
Interest Expense		(175	)		—		(35,902	)		—			(36,077	)
Gain on Derivatives, Net		44,553			—		934			—			45,487
Other Income		118			—		—			—			118
Loss From Equity Method Investments		(411	)		—		—			—			(411	)
Income (Loss) From Equity in Consolidated Subsidiaries		(1,083	)		1,083		(227,955	)		227,955			—
TOTAL OTHER INCOME (EXPENSE)		43,002			1,083		(262,923	)		227,955			9,117
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(218,273	)		1,083		(267,798	)		229,762			(255,226	)
Income Tax (Expense) Benefit		(2,557	)		—		2,557			—			—
INCOME (LOSS) FROM CONTINUING OPERATIONS		(220,830	)		1,083		(265,241	)		229,762			(255,226	)
Income (Loss) From Discontinued Operations, Net of Income Tax		(44,836	)		38,258		—			(1,192	)		(7,770	)
NET INCOME (LOSS)		(265,666	)		39,341		(265,241	)		228,570			(262,996	)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			2,245		—			—			2,245
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(265,666	)	$	37,096	$	(265,241	)	$	228,570		$	(265,241	)
Preferred Stock Dividends		—			—		(7,245	)		—			(7,245	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(265,666	)	$	37,096	$	(272,486	)	$	228,570		$	(272,486	)

38

REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2015

($ in Thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(265,666	)	$	39,341		$	(265,241	)	$	228,570		$	(262,996	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by    Operating Activities
Loss From Equity Method Investments		411			—			—			—			411
Non-Cash Expenses (Income)		(120	)		(334	)		6,145			—			5,691
Depreciation, Depletion, Amortization and Accretion		83,427			3,205			—			(3,766	)		82,866
Loss on Derivatives		(44,553	)		—			(934	)		—			(45,487	)
Cash Settlements of Derivatives		39,168			—			934			—			40,102
Dry Hole Expense		199			275			—			(6	)		468
Gain on Disposal of Assets		(465	)		(44	)		—			—			(509	)
Gain on Sale of Water Solutions		—			—			(57,014	)		—			(57,014	)
Impairment Expense		264,693			1,014			—			(1,030	)		264,677
Changes in operating assets and liabilities
Accounts Receivable		14,602			(478	)		429			(2,538	)		12,015
Inventory, Prepaid Expenses and Other Assets		1,342			(142	)		(108	)		—			1,092
Accounts Payable and Accrued Liabilities		(27,935	)		(4,816	)		4,110			2,538			(26,103	)
Other Assets and Liabilities		(1,748	)		(73	)		27			—			(1,794	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		63,355			37,948			(311,652	)		223,768			13,419
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		79,071			(38,532	)		184,393			(224,932	)		—
Proceeds from Joint Venture Acreage Management		54			—			—			—			54
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		9,557			559			66,135			—			76,251
Proceeds from Joint Venture		16,611			—			—			—			16,611
Acquisitions of Undeveloped Acreage		(26,232	)		(279	)		—			—			(26,511	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(156,432	)		(7,939	)		—			1,164			(163,207	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(77,371	)		(46,191	)		250,528			(223,768	)		(96,802	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			35,813			151,000			—			186,813
Repayments of Long-Term Debt and Lines of Credit		—			(26,335	)		(82,000	)		—			(108,335	)
Repayments of Loans and Other Long-Term Debt		(817	)		(520	)		—			—			(1,337	)
Debt Issuance Costs		—			(3	)		(626	)		—			(629	)
Dividends Paid		—			—			(7,245	)		—			(7,245	)
Distributions by the Partners of Consolidated Subsidiaries		—			(830	)		—			—			(830	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(817	)		8,125			61,129			—			68,437
NET INCREASE (DECREASE) IN CASH		(14,833	)		(118	)		5			—			(14,946	)
CASH – BEGINNING		17,978			118			—			—			18,096
CASH - ENDING	$	3,145		$	—		$	5		$	—		$	3,150

39

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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, 2015 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.

Overview of Our Business

We are an independent oil and gas company operating in the Appalachian Basin, where we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. 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. We are headquartered in State College, Pennsylvania, with a regional office in Cranberry, Pennsylvania.

We believe the outlook for our business is favorable despite the continued uncertainty of oil and gas prices. Our resource base, risk management, including an active hedging program, and disciplined investment of capital provide us with an opportunity to exploit and develop our positions and maximize efficiency in our key operating areas. We continue to focus on maintaining financial flexibility while pursuing an active, technology-driven drilling program to develop and maximize the value of our existing acreage as market conditions continue to evolve.

However, a prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserves, and may result in write-downs of the carrying values of our oil and natural gas properties and revisions to our capital budget or development program. We discuss these matters in further detail under, among other places, “Commodity Prices,” “Impairment Expense,” “Capital Resources and Liquidity,” and “Volatility of Oil, NGL and Natural Gas Prices” below as well as in Note 15, “Impairment Expense”, to our Consolidated Financial Statements.

We have historically divided our operations into two principal business segments, exploration and production (“E&P”) and field services. In June 2016, we entered into a purchase and sale agreement to divest all Illinois Basin components of our E&P operations.  As of June 14, 2016, the Illinois Basin assets became classified as “Held for Sale” and our assets and operations of the Illinois Basin are reported as Discontinued Operations. Closing occurred on August 18, 2016, with an effective date for the transaction of July 1, 2016 in exchange for approximately $40.5 million in proceeds. During the third quarter of 2015, we sold Water Solutions Holdings, LLC (“Water Solutions”) and its related subsidiaries, which accounted for the majority of our field services segment. The sale of Water Solutions closed in July 2015, and we received approximately $66.8 million in proceeds for our 60% interest, net of customary selling expenses. The assets and operating results of Water Solutions are reported as Discontinued Operations. Unless otherwise noted, information presented in management’s discussion and analysis are for continuing operations.  

2016 Activity

During the three and nine months ended September 30, 2016, we produced 18,194 MMcfe and 53,561 MMcfe, respectively. Overall, our production for the three and nine months ended September 30, 2016 averaged 198 MMcfe per day and 195 MMcfe per day, respectively. As of September 30, 2016, we had nine gross (3.2 net) wells drilled and awaiting completion and four gross (2.0 net) wells resting or awaiting pipeline connection. Our drilling and completion activity for the period indicated is set forth in the table below.

40

Three and Nine Months Ended September 30, 2016 and 2015

Three Months Ended September 30, 2016
Wells Drilled				Wells Completed				Wells Placed In Service
Gross		Net		Gross		Net		Gross		Net
	4.0		1.4		3.0		1.8		4.0		2.1
Three Months Ended September 30, 2015
Wells Drilled				Wells Completed				Wells Placed In Service
Gross		Net		Gross		Net		Gross		Net
	10.0		6.9		11.0		5.6		9.0		3.8
Nine Months Ended September 30, 2016
Wells Drilled				Wells Completed				Wells Placed In Service
Gross		Net		Gross		Net		Gross		Net
	14.0		5.6		12.0		6.2		23.0		11.2
Nine Months Ended September 30, 2015
Wells Drilled				Wells Completed				Wells Placed In Service
Gross		Net		Gross		Net		Gross		Net
	28.0		18.1		26.0		12.7		26.0		13.4

Commodity Prices

Our development plans are sensitive to current and projected commodity prices which have been and are expected to continue to be volatile. Our realized price, before derivative settlements, for natural gas during the three and nine months ended September 30, 2016, averaged approximately $1.54 per Mcf and $1.44 per Mcf, respectively, as compared to $1.74 per Mcf and $1.99 per Mcf for the same periods in 2015, respectively. Our realized price, before derivative settlements, for condensate during the three and nine months ended September 30, 2016, averaged approximately $38.82 per barrel and $34.72 per barrel, respectively, as compared to $32.99 per barrel and $35.45 per barrel for the same periods in 2015. Our realized price, before derivative settlements, for C3+ NGLs during the three and nine months ended September 30, 2016, averaged approximately $16.48 per barrel and $14.74 per barrel, respectively, as compared to $10.17 per barrel and $15.83 per barrel for the same periods in 2015. Our realized price, before derivative settlements, for ethane during the three and nine months ended September 30, 2016, averaged approximately $7.99 per barrel and $7.28 per barrel, respectively, as compared to $7.22 per barrel and $6.82 per barrel for the same periods in 2015.

For the three and nine months ended September 30, 2016, we recorded impairment expense of approximately $9.6 million and $45.3 million, respectively. Further decreases in commodity prices will decrease our natural gas, condensate and NGL revenues and could reduce the amount of natural gas, condensate and NGL reserves that we can economically produce. A prolonged period of depressed commodity prices or further declines in projected future commodity prices could require additional write-downs of the carrying values of our properties.

Because we follow the successful efforts method of accounting our impairment tests are largely based on estimates of future commodity prices, changes in development and operating costs, taxes, operational efficiencies, changes in technology and access to capital, which makes predicting any future write-downs difficult and uncertain. In an effort to quantify the impact of continued low commodity pricing levels or further declines in future prices, we offer the following: as of September 30, 2016, approximately 78.1% of our evaluated oil and natural gas properties were located in our Butler Marcellus operating area.  Based on estimates of future cash flows, substantial further decreases in commodity prices combined with a lack of access to capital or a detrimental change to costs or operating efficiencies would need to occur in order for us to experience a write-down. Our remaining evaluated properties outside of the Butler Marcellus operating area are more sensitive to the current commodity price environment. These properties could experience additional write-downs if estimates of future commodity prices decline further. The net book value of these remaining evaluated properties totaled approximately $126.6 million as September 30, 2016.

Senior Note Exchange

On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate

41

principal amount of our new Senior Secured Second Lien Notes (the “New Notes”) and (ii) 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the New Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established.  See Note 9, Income Taxes, to our Consolidated Financial Statements, for information regarding the tax treatment and impact of the Exchange for federal and state income tax purposes.

In exchange for $324.0 million in aggregate principal amount of the 2020 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.2 million aggregate principal amount of New Notes and (ii) issued 8.4 million Shares. An additional $0.5 million aggregate principal amount of New Notes were issued to holders who were ineligible to accept the Shares. In addition, upon closing we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum payable in cash thereafter. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending on October 1, 2020. In connection with the Exchange, we incurred approximately $9.0 million in third-party debt issuance costs in the nine-month periods ending September 30, 2016. These costs were recorded as Debt Exchange Expense in Statement of Operations.

Debt for Equity Exchanges

During the second and third quarters of 2016, we entered into privately negotiated debt-to-equity exchanges with certain holders of our Existing Notes as well as holders of our New Notes in exchange for unrestricted shares of our common stock.  These exchanges resulted in the retirement of $27.7 million of our Existing Notes, and $2.2 million of our New Notes, in exchange for the issuance of a total of approximately 5.2 million shares of unrestricted common stock.  The exchanged notes were subsequently cancelled, resulting in a gain to the company of approximately $23.7 million, presented as Gain on Extinguishment of Debt in our Consolidated Statement of Operations for the three and nine month periods ending September 30, 2016.

During the third quarter of 2016, we entered into a privately negotiated debt-to-equity exchange with a single holder of our New Notes in exchange for unrestricted shares of our common stock. This exchange resulted in the retirement of $43.5 million of our New Notes in exchange for the issuance of approximately 16.8 million shares of unrestricted common stock. The transaction was accounted for as troubled debt restructuring. The exchange resulted in a deferred gain of $32.5 million, which will be amortized over the life of the New Notes through a change to the effective interest rate.

Preferred Stock Exchanges

During the nine months ended September 30, 2016, 12,013 shares of Series A Preferred Stock were converted into approximately 8.4 million shares of common stock pursuant to the terms of the Series A Preferred Stock, and through negotiated exchanges with certain holders of the Series A Preferred Shares.  These exchanges are recorded within equity, and do not affect our Net Loss from Continuing Operations for the three and nine-month periods ending September 30, 2016. See Note 13, Earnings Per Common Share, to our Consolidated Financial Statements, for additional information regarding the effect of the preferred stock conversions on Net Income (Loss) Attributable to Common Shareholders.

Benefit Street Partners, LLC Joint Venture

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, 12 of which have already been drilled, completed, placed in sales and paid for by BSP. The remaining four wells are expected to be placed in sales and paid for by BSP during the fourth quarter of 2016. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells in 2016 and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised their option to participate in 20 of these additional wells, including four that were already drilled.  We expect total consideration for this transaction to be $175.0 million with approximately $120.7 million committed as of September 30, 2016. BSP has paid approximately $52.4 million for their interest in elected wells as of September 30, 2016. The remainder of the proceeds will be received as additional wells are drilled to total depth or

42

placed in sales.  BSP earns an assignment of 15%-20% working interest in acreage located within each of the units they participate. As of September 30, 2016, 20 of the 42 committed wells were in line and producing, nine wells were drilled and awaiting completion and four wells were awaiting pipeline connection.

Diversified Oil & Gas, LLC

On May 20, 2016, we entered into a Purchase and Sale Agreement (“PSA”) with Diversified Oil and Gas, LLC (“DOG”). Pursuant to the PSA, DOG purchased all of our conventional operated oil and gas-related properties and related pipeline assets located in Pennsylvania and assumed all future abandonment liability associated with the assets. Closing occurred on May 20, 2016, with an effective date for the transaction of May 1, 2016. We received proceeds at closing of approximately $0.1 million. Included in the sale were approximately 300 wells, pipelines and support equipment. The sale of well properties generated approximately $4.6 million of gain in the second quarter of 2016, due to the elimination of our future abandonment liability associated with wells and pipelines sold to DOG.  The gain, which is included in Gain on Disposal of Assets on our Consolidated Statement of Operations, is reported net of approximately $0.2 million of uncollectible accounts receivable written off in conjunction with the sale.

Sale of Illinois Basin Operations

On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). Pursuant to the Agreement, Campbell agreed to purchase, subject to certain parameters and provisions for adjustment customary for transactions of this type, all of Rex’s oil and gas-related properties and assets, both operated and non-operated, in the Illinois Basin on an as-is, where-is basis. Closing occurred on August 18, 2016, with an effective date for the transaction of July 1, 2016. We received a purchase deposit of $2.5 million from Campbell in June 2016 and received additional proceeds of approximately $38.0 million during the third quarter (subject to customary closing and post-closing adjustments scheduled to occur during the fourth quarter). An addendum executed in conjunction with the Agreement allows for Rex to receive from Campbell potential additional proceeds of up $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ending December 31, 2016, and ending with the quarter ending June 30, 2019.  For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. 

Calendar Quarter Ending	West Texas Intermediate ("WTI")  Average Price per Bbl (a)
12/31/2016	$	54.25
3/31/2017	$	56.25
6/30/2017	$	58.25
9/30/2017	$	60.25
12/31/2017	$	60.75
3/31/2018	$	61.25
6/30/2018	$	61.75
9/30/2018	$	62.25
12/31/2018	$	62.75
3/31/2019	$	63.25
6/30/2019	$	63.75

Calculated as the sum of the closing spot price of the West Texas Intermediate of the New York Mercantile Exchange for each day during the quarter (excluding weekends and holidays), divided by the number of days on which those prices are published (excluding weekends and holidays).

Included in the sale were approximately 76,000 net acres in Illinois, Indiana and Kentucky and production of approximately 1,700 net barrels per day.  The sale transaction resulted in a full divestiture of our Illinois Basin assets, and an exit from our Illinois Basin operations.  As of June 14, 2016, the Illinois Basin assets became classified as “Held for Sale”, and our assets and operations in the Illinois Basin are reported as Discontinued Operations.

43

Results of Continuing Operations

The following table sets forth summary information regarding NGL, condensate and natural gas production and product prices for the three and nine months ended September 30, 2016 and 2015.

	For the Three Months Ended September 30,				For the Nine Months Ended        September 30,
	2016		2015		2016		2015
Production:
Natural Gas (Mcf)		10,927,477		10,731,248		33,559,096		34,160,329
Condensate (Bbls)		105,517		85,988		259,145		345,726
C3+ NGLs (Bbls)		498,217		498,256		1,495,961		1,571,358
Ethane (Bbls)		607,340		423,479		1,578,480		903,086
Total (Mcfe)(a)		18,193,921		16,777,586		53,560,612		51,081,349
Average daily production:
Natural Gas (Mcf)		118,777		116,644		122,478		125,129
Condensate (Bbls)		1,147		935		946		1,266
C3+ NGLs (Bbls)		5,415		5,416		5,460		5,756
Ethane (Bbls)		6,602		4,603		5,761		3,308
Total (Mcfe)(a)		197,760		182,365		195,477		187,111
Average sales price(b):
Natural Gas (Mcf)	$	1.54	$	1.74	$	1.44	$	1.99
Condensate (Bbls)	$	38.82	$	32.99	$	34.72	$	35.45
C3+ NGLs (per Bbl)	$	16.48	$	10.17	$	14.74	$	15.83
Ethane (per Bbl)	$	7.99	$	7.22	$	7.28	$	6.82
Total (per Mcfe)(a)	$	1.87	$	1.77	$	1.70	$	2.18
Average NYMEX prices(c):
Oil (per Bbl)	$	44.94	$	46.43	$	41.33	$	51.00
Natural Gas (per Mcf)	$	2.80	$	2.73	$	2.34	$	2.76

(a) Condensate, Ethane and C3+ NGLs are converted at the rate of one barrel of oil equivalent (“BOE”) to six Mcfe.

(b) Does not include the effects of cash settled derivatives.

(c) Based upon the average of bid week prompt month prices.

The following table sets forth summary information regarding NGL, condensate and natural gas revenues, production volumes, average product prices and average production costs for the three and nine months ended September 30, 2016 and 2015.

	Production and Revenue by Product
	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2016		2015		2016		2015
Revenue – Natural Gas(a)	$	16,871,451	$	18,684,131	$	48,431,297	$	68,057,175
Volumes (Mcf)		10,927,477		10,731,248		33,559,096		34,160,329
Average Price	$	1.54	$	1.74	$	1.44	$	1.99
Revenue – Condensate (a)	$	4,096,017	$	2,836,869	$	8,998,352	$	12,257,384
Volumes (Bbl)		105,517		85,988		259,145		345,726
Average Price	$	38.82	$	32.99	$	34.72	$	35.45
Revenue – C3+ NGLs(a)	$	8,210,863	$	5,068,550	$	22,053,201	$	24,871,939
Volumes (Bbl)		498,217		498,256		1,495,961		1,571,358
Average Price	$	16.48	$	10.17	$	14.74	$	15.83
Revenue – Ethane(a)	$	4,855,353	$	3,058,408	$	11,494,780	$	6,157,611
Volumes (Bbl)		607,340		423,479		1,578,480		903,086
Average Price	$	7.99	$	7.22	$	7.28	$	6.82
Average Production Cost per Mcfe(b)	$	1.43	$	1.44	$	1.40	$	1.39

(a) Does not include the effects of cash settled derivatives.

(b) Excludes ad valorem and severance taxes.

44

General Overview

Operating revenue for the three and nine months ended September 30, 2016 increased 14.8% and decreased 18.3% when compared to the same periods in 2015, respectively. The decrease in operating revenue for the nine months ended September 30, 2016, can be primarily attributed to lower natural gas prices, partially offset by higher production volumes. Our production grew to 18,194 MMcfe for the three-month period ended September 30, 2016, from 16,778 MMcfe for the three-month period ended September 30, 2015, or approximately 8.4%.  For the nine months ended September 30, 2016, our production increased 4.9% to 53,561 MMcfe from the same period in 2015. For the three month period ended September 30, 2016, our realized sales price for natural gas decreased to $1.54 per Mcf from $1.74 per Mcf, condensate increased to $38.82 per barrel from $32.99 per barrel, C3+ NGLs increased to $16.48 per barrel from $10.17 per barrel, and ethane increased to $7.99 per barrel from $7.22 per barrel, respectively, when compared to the same period in 2015. For the nine month period ended September 30, 2016, our realized sales price for natural gas decreased to $1.44 per Mcf from $1.99 per Mcf, condensate decreased to $34.72 per barrel from $35.45 per barrel, C3+ NGLs decreased to $14.74 per barrel from $15.83 per barrel, and ethane increased to $7.28 per barrel from $6.82 per barrel, respectively, when compared to the same period in 2015.

Operating expenses decreased $56.1 million and $171.1 million for the three and nine months ended September 30, 2016, as compared to the same periods in 2015, respectively. Operating expenses primarily comprise: Production and Lease Operating Expenses, G&A Expenses, Other Operating Expense, Exploration Expenses, Impairment Expense and DD&A Expenses. The decreases in operating expenses were largely attributable to fewer impairment charges, reduced DD&A expense, and gains realized on the disposal of assets. The decrease of many of these operating expenses is consistent with the overall decrease in activity within the industry in conjunction with a decrease in the cost of goods and services and other cost control measures that we have implemented. The decrease in impairment was largely indicative of the increase in commodity prices as compared to March 31, 2016.

Comparison of the Three Months Ended September 30, 2016 to the Three Months Ended September 30, 2015

Gas, condensate and NGL revenue, including the effects of cash settled derivatives, for the three-month periods ended September 30, 2016 and 2015 is summarized in the following table:

	For the Three Months Ended September 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2016		2015		Change			%
Gas sales revenue	$	16,871	$	18,684	$	(1,813	)		(9.7	)%
Gas derivatives realized(a)	$	1,200	$	8,911	$	(7,711	)		(86.5	)%
Total gas revenue and derivatives realized	$	18,071	$	27,595	$	(9,524	)		(34.5	)%
Condensate sales revenue	$	4,096	$	2,837	$	1,259			44.4	%
Oil and condensate derivatives realized(a)	$	93	$	2,694	$	(2,601	)		(96.6	)%
Total condensate revenue and derivatives realized	$	4,189	$	5,531	$	(1,342	)		(24.3	)%
C3+ NGL revenue	$	8,211	$	5,069	$	3,142			62.0	%
C3+ NGL derivatives realized(a)	$	830	$	3,446	$	(2,616	)		(75.9	)%
Total C3+ NGL revenue	$	9,041	$	8,515	$	526			6.2	%
Ethane revenue	$	4,855	$	3,058	$	1,797			58.8	%
Ethane derivatives realized(a)	$	97	$	—	$	97			100.0	%
Total Ethane revenue	$	4,952	$	3,058	$	1,894			61.9	%
Consolidated sales	$	34,033	$	29,648	$	4,385			14.8	%
Consolidated derivatives realized(a)	$	2,219	$	15,050	$	(12,831	)		(85.3	)%
Total NGL, condensate and gas revenue and derivatives realized	$	36,252	$	44,698	$	(8,446	)		(18.9	)%
Total Mcfe Production		18,193,921		16,777,586		1,416,335			8.4	%
Average Realized Price per Mcfe	$	1.99	$	2.66	$	(0.67	)		(25.2	)%

(a) Realized derivatives are included in Other Income (Expense) on our Consolidated Statements of Operations.

Average realized price received for natural gas, condensate and NGLs during the third quarter of 2016, after the effect of derivative activities, was $1.99 per Mcfe, a decrease of 25.2%, or $0.67 per Mcfe, from the same period in 2015. This decrease was primarily due to a decrease in commodity prices during the quarter, partially offset by positive cash settlements on derivatives. The average price for natural gas, after the effect of derivative activities, decreased 35.8%, or $0.92 per Mcf, to $1.65 per Mcf. The average price for condensate, after the effect of derivative activities, decreased 38.3%, or $24.62 per barrel, to $39.70 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, increased 6.8%, or $1.15 per barrel, to $18.15 per barrel. The average price for ethane, after the effect of derivative activities, increased 11.1% or $0.82 per barrel, to $8.15 per barrel. Our derivative activities effectively increased net realized prices by $0.12 per Mcfe in the third quarter of 2016 and $0.61 per Mcfe in the third quarter of 2015.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $1.26 per Mcf during the third quarter of 2016 primarily due to basis differentials in the northeastern United States, which were partially offset by sales on the Texas Eastern pipeline receiving M3 pricing, a New York area index. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. In addition, we have been targeting sales points outside

45

of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast. Transportation of 100,000 Mcf per day to the Gulf Coast will begin during the fourth quarter of 2016.

Production volumes in the third quarter of 2016 increased 8.4% or 1,416.3 Mcfe from the third quarter of 2015 primarily due to the success of our Marcellus and Utica Shale horizontal drilling activities in the liquids-rich portion of our acreage holdings. Natural gas production decreased approximately 1.8%, condensate production increased approximately 22.7%, C3+ NGL production was flat and our ethane production increased approximately 43.4%. Reductions in natural gas production volumes are related to the increase in ethane production volumes, as the amount of ethane extraction from produced natural gas is controlled at the processing plant.  The product blend is optimized for pricing and demand conditions.

Overall, our production for the third quarter of 2016 averaged 197,760 Mcfe per day, of which 60.1% was attributable to natural gas, 3.5% to condensate, 20.0% to C3+ NGLs and 16.4% was a result of ethane production.

Statements of Operations for the three-month periods ended September 30, 2016 and 2015 are as follows:

	For the Three Months Ended September 30,
($ in Thousands)	2016			2015			Change			%
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	34,034		$	29,648		$	4,386			14.8	%
Other Operating Revenue		5			8			(3	)		(37.5	)%
TOTAL OPERATING REVENUE		34,039			29,656			4,383			14.8	%
OPERATING EXPENSES
Production and Lease Operating Expense		26,333			24,259			2,074			8.5	%
General and Administrative Expense		5,116			4,507			609			13.5	%
(Gain) Loss on Disposal of Assets		10			(224	)		234			(104.5	)%
Impairment Expense		9,563			85,193			(75,630	)		(88.8	)%
Exploration Expense		216			580			(364	)		(62.8	)%
Depreciation, Depletion, Amortization and Accretion		15,109			20,832			(5,723	)		(27.5	)%
Other Operating Expense		9,899			190			9,709			5,110.0	%
TOTAL OPERATING EXPENSES		66,246			135,337			(69,091	)		(51.1	)%
LOSS FROM OPERATIONS		(32,207	)		(105,681	)		73,474			(69.5	)%
OTHER INCOME (EXPENSE)
Interest Expense		(9,646	)		(11,884	)		2,238			(18.8	)%
Gain on Derivatives, Net		16,866			28,649			(11,783	)		(41.1	)%
Other Income		16			25			(9	)		(36.0	)%
Debt Exchange Expense		(35	)		—			(35	)		100.0	%
Gain on Extinguishment of Debt		423			—			423			100.0	%
TOTAL OTHER INCOME		7,624			16,790			(9,166	)		(54.6	)%
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(24,583	)		(88,891	)		64,308			(72.3	)%
Income Tax Benefit		8,106			—			8,106			100.0	%
LOSS FROM CONTINUING OPERATIONS		(16,477	)		(88,891	)		72,414			(81.5	)%
Income (Loss) From Discontinued Operations, Net of Income Taxes		21,892			(5,785	)		27,677			(478.4	)%
NET INCOME (LOSS)		5,415			(94,676	)		100,091			(105.7	)%
Net Loss Attributable to Noncontrolling Interests		—			(1	)		1			(100.0	)%
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	5,415		$	(94,675	)	$	100,090			(105.7	)%

Production and Lease Operating Expense increased approximately $2.1 million, or 8.5%, in the third quarter of 2016 from the same period in 2015. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells and related production as they relate to variable type costs such as transportation, marketing, processing and gathering. Transportation, marketing, processing and gathering fees accounted for approximately 87.0% of our total Production and Lease Operating Expense in the third quarter of 2016, as compared to 86.0% from the same period in 2015. As we continue to develop our core areas of operation we expect that fees incurred from unutilized commitments will decrease. 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. On a per unit of production basis, our lifting costs were $1.45 per Mcfe in each of the three months ended September 30, 2016 and 2015.

G&A Expense for the third quarter of 2016 increased approximately $0.6 million, or 13.5%, to $5.1 million from the same period in 2015. Non-cash compensation increased $1.0 million due to employee terminations in 2015 that caused a one-time credit to G&A net of decreases in 2016 for overall reductions in head count, a decrease in travel expenditures, less usage of third-party consultants and pricing concessions received from suppliers and service providers.

46

Impairment Expense for the third quarter of 2016 was approximately $9.6 million. We evaluate impairment of our properties when events occur that indicates that the carrying value of these properties may not be recoverable. The expense incurred during the third quarter of 2016 included $9.0 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County and Lawrence County, Pennsylvania, and Warrior County, Ohio. Based on the current commodity price environment, we do not expect to develop these properties prior to expiration of the associated leases. Impairment of proved properties in our Butler County operations totaled approximately $0.6 million during the third quarter of 2016. The impairments were identified through an analysis of market conditions and future development plans related to these properties that were in existence as of September 30, 2016, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. Any amount of future impairments are difficult to predict, however, if commodity prices decline, downward revisions of proved reserves may be significant and could result in additional impairment expense.

Exploration Expense for the third quarter of 2016 was approximately $0.2 million, as compared to $0.6 million for same period in 2015. The expense incurred in 2016 was due to geological and geophysical type expenditures. Approximately $0.1 million of the expense incurred in 2015 was due to geological and geophysical type expenditures and $0.5 million was due to payment of delay rentals. As a result of the decrease in commodity prices, we have decreased our levels of spending with regards to geological and geophysical activities.

DD&A Expense for the third quarter of 2016 decreased approximately $5.7 million, or 27.5%, from $20.8 million for the same period in 2015. Contributing to the decrease in DD&A expense were lower third quarter depreciable asset values from the impact of 2015 impairments, partially offset by lower year end reserves, which were triggered by the ongoing lower commodity pricing environment and the related effect on our estimated proved reserves, when compared to the same period in 2015.

Other Operating Expense for the third quarter of 2016 increased approximately $9.7 million from $0.2 million for the same period in 2015. The expense in 2016 is primarily related to a firm transportation contract associated with an area west of our core assets in Butler County, Pennsylvania. During the third quarter of 2016, we elected to cease all future development activities in the area associated with this contract, and recorded $8.3 million to Other Operating Expense, representing the expense equal to the present value of our full future obligations under the contract.

Interest Expense for the third quarter of 2016 was approximately $9.6 million as compared to $11.9 million for the same period in 2015. The decrease in interest expense is primarily due to reduced bond interest expense as a result of the Senior Notes exchange completed on March 31, 2016.  The decrease is partially offset by increased amortization of bond costs as a result of the Senior Notes exchange, and increased interest expense due to increased borrowing on our revolving credit facility. We discuss our Senior Notes and revolving credit facility in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Gain on Derivatives, net included a gain of approximately $16.9 million for the third quarter of 2016 as compared to a gain of $28.6 million for the same period in 2015. The gain recorded for the third quarter of 2016 included cash receipts for commodity derivatives of $2.1 million while the gain incurred in the third quarter of 2015 included cash receipts of approximately $15.1 million for commodity and interest rate derivatives. 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.

We believe oil, NGL and natural gas prices will remain volatile and could decline further. Although we have entered into derivative contracts covering a portion of our production volumes for the remainder of 2016 and 2017, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

Gain on Extinguishment of Debt for the third quarter of 2016 totaled approximately $0.4 million.  The gain resulted from debt to equity exchanges under troubled debt restructuring rules with certain holders of our Senior Notes, wherein approximately $29.1 million of outstanding Senior Notes were reacquired by the company in exchange for approximately 5.2 million shares of our common stock.  We discuss the debt to equity exchanges in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Income Tax Benefit for the third quarter of 2016 was $8.1 million, or 33.0% of pretax loss, for federal and state income taxes on continuing operations.  Though a full valuation allowance has been recorded against net deferred tax assets at September 30, 2016, a tax benefit is being recorded in continuing operations to offset the tax expense resulting from pretax income in discontinued operations.  This tax benefit is reduced by a tax charge for alternative minimum tax with no corresponding deferred tax benefit on minimum tax credit carryforwards due to the full valuation allowance, and state taxes in certain tax paying jurisdictions.  The

47

Company’s alternative minimum tax expected to be due for 2016 is primarily driven by cancellation of debt income of $543.2 million related to the Senior Note exchange discussed in Note 7, Long-Term Debt, to our Consolidated Financial Statements. Refer to Note 9, Income Taxes, to our Consolidated Financial Statements for additional information regarding income taxes.

For the third quarter of 2015, the estimated annual effective tax rate applied to ordinary losses from continuing operations was 0.0% due to the recording of full valuations allowances against the tax benefits generated by pretax losses, resulting in recognition of no tax benefit for the period. 

Net Income (Loss) Attributable to Rex Energy for the third quarter of 2016 was income of approximately $5.4 million, as compared to a loss of $94.7 million for the same period in 2015 as a result of factors discussed above.

Comparison of the Nine Months Ended September 30, 2016 to the Nine Months Ended September 30, 2015

Gas, condensate and NGL revenue, including the effects of cash settled derivatives, for the nine-month periods ended September 30, 2016 and 2015 is summarized in the following table:

	For  the Nine Months Ended September 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2016		2015		Change			%
Gas sales revenue	$	48,431	$	68,057	$	(19,626	)		(28.8	)%
Gas derivatives realized(a)	$	24,280	$	23,250	$	1,030			4.4	%
Total gas revenue and derivatives realized	$	72,711	$	91,307	$	(18,596	)		(20.4	)%
Condensate sales revenue	$	8,998	$	12,257	$	(3,259	)		(26.6	)%
Oil and condensate derivatives realized(a)	$	2,191	$	8,807	$	(6,616	)		(75.1	)%
Total condensate revenue and derivatives realized	$	11,189	$	21,064	$	(9,875	)		(46.9	)%
C3+ NGL revenue	$	22,053	$	24,872	$	(2,819	)		(11.3	)%
C3+ NGL derivatives realized(a)	$	6,040	$	7,111	$	(1,071	)		(15.1	)%
Total C3+ NGL revenue	$	28,093	$	31,983	$	(3,890	)		(12.2	)%
Ethane revenue	$	11,495	$	6,158	$	5,337			86.7	%
Ethane derivatives realized(a)	$	241	$	—	$	241			100.0	%
Total Ethane revenue	$	11,736	$	6,158	$	5,578			90.6	%
Consolidated sales	$	90,977	$	111,344	$	(20,367	)		(18.3	)%
Consolidated derivatives realized(a)	$	32,752	$	39,168	$	(6,416	)		(16.4	)%
Total NGL, condensate and gas revenue and derivatives realized	$	123,729	$	150,512	$	(26,783	)		(17.8	)%
Total Mcfe Production		53,560,612		51,081,349		2,479,263			4.9	%
Average Realized Price per Mcfe	$	2.31	$	2.95	$	(0.64	)		(21.6	)%

(a) Realized derivatives are included in Other Income (Expense) on our Consolidated Statements of Operations.

Average realized price received for natural gas, condensate and NGLs during the first nine months of 2016, after the effect of derivative activities, was $2.31 per Mcfe, a decrease of 21.6%, or $0.64 per Mcfe, from the same period in 2015. This decrease was primarily due to a decrease in commodity prices during the quarter, partially offset by positive cash settlements on derivatives. The average price for natural gas, after the effect of derivative activities, decreased 18.9%, or $0.51 per Mcf, to $2.17 per Mcf. The average price for condensate, after the effect of derivative activities, decreased 29.1%, or $17.75 per barrel, to $43.18 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, decreased 7.7%, or $1.57 per barrel, to $18.78 per barrel. The average price for ethane, including the effect of derivatives, increased 6.1% or $0.43 per barrel, to $7.43 per barrel. Our derivative activities effectively increased net realized prices by $0.61 per Mcfe in the first nine months of 2016 and $0.77 per Mcfe in the first nine months of 2015. Excluding the effect of derivative liquidations during the third quarter of 2016, realized prices during the first nine months of 2016 for natural gas and C3+ NGLs would have been approximately $2.07 per mcf and $18.11 per barrel, respectively.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $0.90 per Mcf during the first nine months of 2016 primarily due to basis differentials in the northeastern United States, which were partially offset by sales on the Texas Eastern pipeline, receiving M3 pricing, a New York area index. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. 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. Transportation of 100,000 Mcf per day to the Gulf Coast will begin during the fourth quarter of 2016.

Production volumes in the first nine months of 2016 increased 4.9% or 2,479 Mcfe from the first quarter of 2015 primarily due to the success of our Marcellus and Utica Shale horizontal drilling activities in the liquids-rich portions of our acreage holdings. Natural gas production decreased approximately 1.8%, condensate production decreased approximately 25.0%, C3+ NGL production

48

decreased approximately 4.8% and our ethane production increased approximately 74.8%. Reductions in natural gas production volumes are related to the increase in ethane production volumes, as the amount of ethane extraction from produced natural gas is controlled at the processing plant.  The product blend is optimized for pricing and demand conditions.

Overall, our production for the first nine months of 2016 averaged 194,322 Mcfe per day, of which 62.7% was attributable to natural gas, 2.9% to condensate, 16.8% to C3+ NGLs and 17.7% was a result of ethane production.

Statements of Operations for the nine-month periods ended September 30, 2016 and 2015 are as follows:

	For the Nine Months Ended September 30,
($ in Thousands)	2016			2015			Change			%
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	90,978		$	111,344		$	(20,366	)		(18.3	)%
Other Operating Revenue		12			30			(18	)		(60.0	)%
TOTAL OPERATING REVENUE		90,990			111,374			(20,384	)		(18.3	)%
OPERATING EXPENSES
Production and Lease Operating Expense		76,005			71,646			4,359			6.1	%
General and Administrative Expense		15,237			20,253			(5,016	)		(24.8	)%
Gain on Disposal of Assets		(4,285	)		(533	)		(3,752	)		703.9	%
Impairment Expense		45,344			209,880			(164,536	)		(78.4	)%
Exploration Expense		1,954			1,774			180			10.1	%
Depreciation, Depletion, Amortization and Accretion		46,371			67,369			(20,998	)		(31.2	)%
Other Operating Expense		10,930			5,328			5,602			105.1	%
TOTAL OPERATING EXPENSES		191,556			375,717			(184,161	)		(49.0	)%
LOSS FROM OPERATIONS		(100,566	)		(264,343	)		163,777			(62.0	)%
OTHER INCOME (EXPENSE)
Interest Expense		(34,115	)		(36,077	)		1,962			(5.4	)%
Gain (Loss) on Derivatives, Net		(8,254	)		45,487			(53,741	)		(118.1	)%
Other Income		28			118			(90	)		(76.3	)%
Debt Exchange Expense		(9,048	)		—			(9,048	)		100.0	%
Gain on Extinguishment of Debt		24,130			—			24,130			100.0	%
Loss on Equity Method Investments		—			(411	)		411			(100.0	)%
TOTAL OTHER EXPENSE		(27,259	)		9,117			(36,376	)		(399.0	)%
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(127,825	)		(255,226	)		127,401			(49.9	)%
Income Tax Benefit		5,785			—			5,785			100.0	%
LOSS FROM CONTINUING OPERATIONS		(122,040	)		(255,226	)		133,186			(52.2	)%
Income (Loss) From Discontinued Operations, Net of Income Taxes		12,719			(7,770	)		20,489			(263.7	)%
NET LOSS		(109,321	)		(262,996	)		153,675			(58.4	)%
Net Income Attributable to Noncontrolling Interests		—			2,245			(2,245	)		(100.0	)%
NET LOSS ATTRIBUTABLE TO REX ENERGY	$	(109,321	)	$	(265,241	)	$	155,920			(58.8	)%

Production and Lease Operating Expense increased approximately $4.4 million, or 6.1%, in the first nine months of 2016 from the same period in 2015. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells and related production as they relate to variable type costs such as transportation, marketing, processing and gathering. Transportation, marketing, processing and gathering fees accounted for approximately 87.1% of our total Production and Lease Operating Expense in the first nine months of 2016, as compared to 84.1% from the same period in 2015. As we continue to develop our core areas of operation we expect that fees incurred from unutilized commitments will decrease. 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. On a per unit of production basis, our lifting costs increased to $1.42 per Mcfe in the nine months ended September 30, 2016 from $1.40 per Mcfe in the same period in 2015.

G&A Expense for the first nine months of 2016 decreased approximately $5.0 million, or 24.8%, to $15.2 million from the same period in 2015. We have undertaken several cost control measures during the first nine months of 2016, including reductions in bonus compensation, reductions in head count, a decrease in travel expenditures, less usage of third-party consultants and pricing concessions received from suppliers and service providers.  During the first quarter of 2016, the board of directors approved certain performance factors for restricted stock that vested in March 2016.  These performance factors resulted in reduced expense due to forfeitures on performance-based restricted stock awards of approximately $1.6 million.

49

Gain on Disposal of Assets was $4.3 million for the first nine months of 2016.  The gain was generated primarily by elimination of our future abandonment liability associated with the sale of our operated conventional gas wells and pipelines.  Gains from the disposal of assets in the first nine months of 2015 were negligible.

Impairment Expense for the first nine months of 2016 was approximately $45.3 million. We evaluate impairment of our properties when events occur that indicates that the carrying value of these properties may not be recoverable. The expense incurred during the first nine months of 2016 included $43.8 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County and Lawrence County, Pennsylvania, and Warrior North in Ohio. Based on the current commodity price environment, we do not expect to develop these properties prior to expiration of the associated leases. Impairment of proved properties in our Butler County operations totaled approximately $1.5 million during the third quarter of 2016. The impairments were identified through an analysis of market conditions and future development plans related to these properties that were in existence as of September 30, 2016, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. Any amount of future impairments are difficult to predict, however, if commodity prices decline, downward revisions of proved reserves may be significant and could result in additional impairment expense.

Exploration Expense for the first nine months of 2016 was approximately $2.0 million, as compared to $1.8 million for same period in 2015. Approximately $1.1 million of the expense incurred in 2016 was due to geological and geophysical type expenditures and $0.9 million was due to costs associated with exploratory wells that were abandoned at various stages, resulting in dry hole expense. Approximately $0.6 million of the expense incurred in 2015 was due to geological and geophysical type expenditures, $1.0 million was due to payment of delay rentals, and $0.2 million was due to costs associated with exploratory wells that were abandoned at various stages, resulting in dry hole expense. As a result of the decrease in commodity prices, we have decreased our levels of spending with regards to geological and geophysical activities.

DD&A Expense for the first nine months of 2016 decreased approximately $21.0 million, or 31.2%, from $67.4 million for the same period in 2015. Contributing to the decrease in DD&A expense were lower first quarter depreciable asset values from the impact of 2015 impairments, partially offset by lower year end reserves, which were triggered by the ongoing lower commodity pricing environment and the related effect on our estimated proved reserves, when compared to the same period in 2015.

Other Operating Expense for the first nine months of 2016 increased to approximately $10.9 million from $5.3 million in the first nine months of 2015. The expense in 2016 is primarily related to a firm transportation contract associated with an area west of our core assets in Butler County, Pennsylvania. During the third quarter of 2016, we elected to cease all future development activities in the area associated with this contract and recorded $8.3 million to Other Operating Expense, representing the expense equal to the present value of our full future obligations under the contract. During the first nine months of 2015, in addition to $0.5 million in unutilized firm capacity commitments, we incurred rig termination charges of approximately $4.8 million for the cancellation of drilling rig contracts before expiration of their original term.

Interest Expense for the nine months ended September 30, 2016 was approximately $34.1 million as compared to $36.1 million for the same period in 2015. The decrease in interest expense is primarily due to reduced bond interest expense as a result of the Senior Notes exchange completed on March 31, 2016.  The decrease is partially offset by increased amortization of bond costs as a result of the Senior Notes exchange, and increased interest expense due to increased borrowing on our revolving credit facility. We discuss our Senior Notes and revolving credit facility in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Gain (Loss) on Derivatives, net included a loss of approximately $8.3 million for the first nine months of 2016 as compared to a gain of approximately $45.5 million for the same period in 2015. The loss recorded for the first nine months of 2016 included cash receipts for commodity derivatives of $32.5 million while the gain incurred in the first quarter of 2015 included cash receipts of approximately $40.1 million for commodity and interest rate derivatives. 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.

We believe oil, NGL and natural gas prices will remain volatile and could decline further. Although we have entered into derivative contracts covering a portion of our production volumes for the remainder of 2016 and 2017, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

50

Debt Exchange Expense for the nine months ended September 30, 2016 totaled approximately $9.0 million. These charges relate to our exchange of Existing for New Notes completed on March 31, 2016. We accounted for the exchange as a troubled debt restructuring, which mandates that current third-party expenses be charged against income in the current period.

Gain on Extinguishment of Debt for the nine months ended September 30, 2016 totaled approximately $24.1 million.  The gain resulted from debt to equity exchanges under troubled debt restructuring rules with certain holders of our Senior Notes, wherein approximately $29.1 million of outstanding Senior Notes were reacquired by the company in exchange for approximately 5.2 million shares of our common stock.  We discuss the debt to equity exchanges in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Income Tax Benefit for the nine months ended September 30, 2016 was $5.8 million, or 4.5% of pretax loss, for federal and state income taxes on continuing operations. Though a full valuation allowance has been recorded against net deferred tax assets at September 30, 2016, a tax benefit is being recorded in continuing operations to offset the tax charge resulting from pretax income in discontinued operations. This tax benefit is reduced by a tax charge for alternative minimum tax with no corresponding deferred tax benefit on minimum tax credit carryforwards due to the full valuation allowance, and state taxes in certain tax paying jurisdictions. The Company’s alternative minimum tax expected to be due for 2016 is primarily driven by cancellation of debt income of $543.2 million related to the Senior Note exchange discussed in Note 7, Long-Term Debt, to our Consolidated Financial Statements. Refer to Note 9, Income Taxes, to our Consolidated Financial Statements for additional information regarding income taxes.

For the nine months ended September 30, 2015, the estimated annual effective tax rate applied to ordinary losses from continuing operations was 0.0% due to the recording of full valuations allowances against the tax benefits generated by pretax losses, resulting in recognition of no tax benefit for the period.

Net Loss Attributable to Rex Energy for the first nine months of 2016 was approximately $109.3 million, as compared to a loss of $265.2 million for the same period in 2015 as a result of factors discussed above.

	Other Performance Measurements
	For Three Months Ended September 30,				For Nine Months Ended September 30,
	2016		2015		2016		2015
EBITDAX from Continuing Operations ($ in Thousands) (a)	$	4,536	$	15,585	$	32,031	$	63,549
LOE per Mcfe	$	1.45	$	1.45	$	1.42	$	1.40
G&A per Mcfe	$	0.28	$	0.27	$	0.28	$	0.40

(a) EBITDAX is a non-GAAP measure. See “Non-GAAP Financial Measures” for our reconciliation of EBITDAX to net income.

EBITDAX (Non-GAAP)

EBITDAX (Non-GAAP) from continuing operations decreased approximately $11.4 million to $4.1 million for the three-month period ended September 30, 2016, as compared to the same period in 2015.  EBITDAX from continuing operations decreased approximately $31.9 million to $31.6 million for the nine-month period ended September 30, 2016, as compared to the same period in 2015. The decrease in EBITDAX can be primarily attributed to decreased average sales prices for natural gas and condensate, resulting in decreased operating revenues. In addition to the direct revenue impact of lower commodity prices, our EBITDAX has also been impacted by the effect of lower effective strike prices on our commodity derivatives, resulting in a decrease in the cash settlements of our derivatives.

LOE per Mcfe

LOE per Mcfe measures the average cost of extracting natural gas, condensate and NGLs from our 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 natural gas and NGL reserves in the ground. LOE per Mcfe remaining flat at $1.45 for the three months ended September 30, 2016, as compared to $1.45 for the same period in 2015. LOE per Mcfe increased to $1.42 for the nine months ended September 30, 2016, as compared to $1.40 for the same period in 2015. Our LOE is largely comprised of variable type costs such as transportation, marketing, processing and gathering. For the third quarter of 2016, transportation, capacity and processing fees accounted for approximately 87.0% of our total Production and Lease Operating Expense as compared to 86.0% during the same period of 2015. For the nine months ended September 30, 2016, transportation, capacity and processing fees accounted for approximately 87.1% of our total Production and Lease Operating Expense as compared to 84.1% during the same period of 2015. These agreements typically have a term of several years, and we expect them to continue to comprise a significant

51

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, we expect our lifting cost to decrease as we gain additional efficiencies of scale and utilize all of our firm capacity and transportation commitments.

G&A Expenses per Mcfe

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 increased to approximately $0.28 for the three-month period ended September 30, 2016, as compared to $0.27 for the same period in 2015. During the first nine months of 2016, G&A per Mcfe decreased to $0.28 as compared to $0.40 for the same period in 2015. The decreases are predominately due to further cost control measures and headcount reductions implemented during the first nine months of 2016 in response to our decreased capital plan related to commodity price declines combined with our increase in production.

Capital Resources and Liquidity

Our primary needs for cash are for the exploration, development and acquisition of oil and gas properties. During the nine months ended September 30, 2016, we spent $35.5 million of capital on asset acquisitions, drilling projects, facilities and related equipment and acquisitions of unproved acreage. We expect to be reimbursed by joint venture partners for approximately $11.7 million of costs incurred during the third quarter of 2016 that were not billed until the fourth quarter. We funded our capital program with proceeds from our Senior Credit Facility, cash from operations and funds received from the closing of the BSP joint development agreement. The remainder of our 2016 capital budget is expected to be funded primarily by cash on hand, cash flows from operations, and potential future asset sales and joint ventures.

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 national and global supply and demand for hydrocarbons. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Historically, we have primarily used cash flows from operations, borrowings from our revolving credit facility and net proceeds from debt and equity offerings to fund the exploration and development of our oil and gas interests. As of September 30, 2016, we had approximately $2.5 million of cash on hand and outstanding borrowings under our $190.0 million revolving credit facility of approximately $131.7 million with an additional $42.9 million of undrawn letters of credit outstanding. Our borrowing base was reaffirmed at $190.0 million effective October 1, 2016. Our next borrowing base redetermination is scheduled to occur on or around April 1, 2017. In May 2016, a third-party midstream provider drew on an outstanding letter of credit in the amount of $3.9 million related to an ongoing gas transportation project for which we declined to provide additional collateral. During October 2016, the $3.9 million was returned to us and a new letter of credit was issued.

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 natural gas reserves. If commodity prices decrease further, 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 natural gas reserves through acquisitions and our development and exploration programs, we may also suffer a reduction in our operating cash flows and access to funds under our revolving credit facility. At September 30, 2016, we were in compliance with all required debt covenants under our revolving credit facility.

Due to the current depressed commodity price environment, in January 2016, we suspended payment of our quarterly dividend on shares of our Series A Convertible, Perpetual Preferred Stock. We have the ability to continue to suspend dividend payments and will continue to evaluate the payment of these dividends on a quarterly basis. As a result of not declaring the first quarter dividend on our Series A Preferred Stock, we are no longer eligible to use Form S-3 registration statements. Until we are again eligible to use Form S-3, we will be required to use a registration statement on Form S-1 to register securities with the SEC (for initial issuance or resale) or issue securities in private placements, which could increase the cost of raising capital. We may need to take additional actions in the future to address current industry trends and maintain our ability to pay expenses and service our indebtedness, including, but not limited to, selling assets or raising capital by issuing additional debt or equity securities.

We have Existing Notes and New Notes (together, the “Senior Notes”) that are governed by indentures with substantially similar terms and provisions (the “Indentures”).  The Indentures contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or

52

permitted.  Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25 to 1.00.  As of September 30, 2016, our Fixed Charge Coverage Ratio was 1.20 to 1.00. We expect our Fixed Charge Coverage Ratio to improve in 2016 based on our projections of decreased interest expense related to our Senior Notes.  As of September 30, 2016, we were limited to incurring an additional $109.2million in debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default, including cross-default features with any other indebtedness. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding notes to be due and payable immediately.

We are not restricted as to our borrowings under our revolving credit facility; however we are subject to the minimum financial requirements detailed in Note 7, Long-Term Debt, to our Consolidated Financial Statements. If we are unable to comply with these financial requirements, an event of default could result which would permit acceleration of outstanding debt and could permit our lenders to foreclose on our mortgaged properties. In addition, our Senior Credit Facility restricts the amount of cash and cash equivalents that we can hold on our Consolidated Balance Sheet to a maximum of $15.0 million, with any excess to be used to pay down the outstanding Senior Credit Facility balance; however we retain the right to draw on the revolving credit facility so long as there are amounts available under our borrowing base.

Future Liquidity Considerations

In connection with certain marketing, transportation and processing agreements that we have entered into, we may be obligated to pay minimum fees in connection with these agreements of $195.9 million over the next five years, depending on our levels of production. In connection with certain of these agreements, weconcurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $408.2 millionover the life of the agreements. These guarantees will decrease over time as the commitments are satisfied.

Our revolving credit facility contains a number of restrictive covenants and limitations that impose significant operating and financial restrictions on us. In particular, our financial covenants require us to maintain a minimum consolidated current ratio of 1.0 to 1.0 and a maximum ratio of net senior-secured debt to EBITDAX, a non-GAAP measure, of 2.75 to 1.0. Failure to comply with these covenants could have a material adverse effect on our business. If an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder:

• Would not be required to lend any additional amounts to us;

• Could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

• May have the ability to require us to apply all of our available cash to repay these borrowings; or

• May prevent us from making debt service payments under our other agreements.

In order to improve our liquidity positions to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, or other financing or strategic counterparties, including (i) debt-for-debt or debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing capital expenditures, (iv) improving cash flows from operations, (v) effectively managing working capital, (vi) adding hedging positions, (vii) asset sales, and (viii) in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations.

Financial Condition and Cash Flows for the Nine Months Ended September 30, 2016 and 2015

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

	Nine Months Ended September 30,
($ in Thousands)	2016			2015
Cash flows provided by (used in) operations	$	(18,473	)	$	13,419
Cash flows provided by (used in) investing activities		5,328			(96,802	)
Cash flows provided by financing activities		14,578			68,437
Net increase (decrease) in cash and cash equivalents	$	1,433		$	(14,946	)

Net cash provided by (used in) operating activities decreased from cash provided by operating activities of $13.4 million in the first nine months of 2015 to cash used of $18.5 million for the same period in 2016. This was primarily due to a reduction in

53

condensate, C3+ NGL and natural gas prices, a decrease in the cash settlement of derivatives and approximately $9.0 million of Debt Exchange Expense. These decreases in cash flow were partially offset by increases in production.

Net cash provided by (used in) investing activities increased from cash used of $96.8 million in 2015 to cash provided of $5.3 million in 2016. This change is primarily attributed to lower activity levels related to the currently depressed commodity price environment. There was $54.9 million of capital activity net of $19.5 million received from our joint venture with BSP in 2016 compared with the $189.7 million of capital activity net of $16.6 million received from our joint venture with ArcLight during the first nine months of 2015. The increase in cash provided by investing activities was partially offset by a decrease in the proceeds received from asset sales.

Net cash provided by financing activities decreased by approximately $53.9 million for the first nine months of 2016 to $14.6 million from $68.4 million over the same period in 2015. The decrease in cash provided is primarily due to lower net borrowings on our revolving credit facility and dividends paid during the first nine months of 2015.

As market conditions warrant and subject to our contractual restrictions in the Senior Credit Facility, our Indentures or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure in open market or privately negotiated transactions, which may include, among other things, repurchases of outstanding equity securities or outstanding debt, including our Senior Notes, by tender offer, exchange or otherwise. The amounts involved in any such transaction, individually or in the aggregate, may be material.

Effects of Inflation and Changes in Price

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.

Critical Accounting Policies and Recently Adopted Accounting Pronouncements

During the quarter ended September 30, 2016, 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, 2015. We describe critical recently adopted and issued accounting standards in Part I, Item 1. Financial Statements—Note 5, “Recently Issued Accounting Pronouncements.”

Non-GAAP Financial Measures

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, 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:

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

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

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

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

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (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.

54

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)	2016			2015			2016			2015
Net Loss From Continuing Operations	$	(16,477	)	$	(88,891	)	$	(122,040	)	$	(255,226	)
Add Back (Less) Non-Recurring Costs1		8,306			—			(6,388	)		4,774
Add Back Depletion, Depreciation, Amortization and Accretion		15,109			20,832			46,371			67,369
Add Back (Less) Non-Cash Compensation Expense		990			(222	)		2,006			4,413
Add Back Interest Expense		9,646			11,884			34,115			36,077
Add Back Impairment Expense		9,563			85,193			45,344			209,880
Add Back Exploration Expenses		216			580			1,954			1,774
Add Back (Less) (Gain) Loss on Disposal of Assets		10			(224	)		(4,285	)		(533	)
Add Back (Less) (Gain) Loss on Financial Derivatives		(16,866	)		(28,649	)		8,254			(45,487	)
Add Back Cash Settlement of Derivatives		2,145			15,082			32,485			40,102
Less Income Tax Expense Benefit		(8,106	)		—			(5,785	)		—
Add Back Non-Cash Portion of Equity Method Investments		—			—			—			406
EBITDAX From Continuing Operations	$	4,536		$	15,585		$	32,031		$	63,549
Net Income (Loss) From Discontinued Operations	$	21,892		$	(5,785	)	$	12,719		$	(7,770	)
Income (Loss) Attributable to Noncontrolling Interests		—			1			—			(2,245	)
Income (Loss) From Discontinued Operations Attributable to Rex Energy		21,892			(5,784	)		12,719			(10,015	)
Add Back Depletion, Depreciation, Amortization and Accretion		18			6,294			5,100			15,497
Add Back (Less) Non-Cash Compensation Expense		(366	)		140			(107	)		421
Add Back Interest Expense		1			59			4			507
Add Back Impairment Expense		—			54,619			3,543			54,797
Add Back Exploration Expenses		—			227			143			468
Less Gain on Disposal of Assets		(30,491	)		(57,024	)		(30,535	)		(56,988	)
Less Non-Cash Portion of Noncontrolling Interests		—			(23	)		—			(209	)
Add Back Income Tax Expense		8,354			2,416			7,852			2,658
Add EBITDAX From Discontinued Operations	$	(592	)	$	924		$	(1,281	)	$	7,136
EBITDAX (Non-GAAP)	$	3,944		$	16,509		$	30,750		$	70,685

1 For the three and nine months ended September 30, 2016, includes approximately $8.3 million in expense related to a firm transportation contract. During the third quarter of 2016, we elected to cease all future development activities in the area associated with the contract. For the three months ended September 30, 2016, includes $0.4 million in gains on the extinguishment of debt. For the nine months ended September 30, 2016, includes approximately $24.1 million in gains on the extinguishment of debt and $9.0 million in debt exchange expenses. For the three and nine months ended September 30, 2015, includes net fees incurred to terminate two drilling rig contracts earlier than their original term.

Volatility of Oil, NGL and Natural Gas Prices

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

55

For the three and nine months ended September 30, 2016, we received net settlements on oil, NGL and natural gas derivatives of approximately $2.2 million and $32.8 million, respectively, as compared to receiving net settlements of approximately $15.1 million and $39.2 million for the three and nine months ended September 30, 2015, respectively. These gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. As of September 30, 2016, we had over 100.0% of our annualized condensate production hedged through the remainder of 2016, over 90.0% and 65.0% of our annualized natural gas production hedged through the remainder of 2016 and 2017, respectively, and over 50.0% of our annualized NGL production hedged through the remainder of 2016. These percentages exclude the effects of our Illinois Basin production and 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 natural gas, condensate and NGL production.

Our primary sources of production and revenue are located in the Appalachian Basin. Natural gas prices in the Appalachian Basin are exposed to regional basis differentials when compared to NYMEX pricing. During the three and nine months ended September 30, 2016, our average realized prices for natural gas was lower than the average NYMEX prices over the same period by approximately $1.26 per Mcf and $0.90 per Mcf. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. We have basis swaps in place for 2,925 MMcf at an average differential to Henry Hub NYMEX of $0.90 per Mcf for the remainder of 2016 in addition to basis swaps for 19,150 MMcf at an average differential to Henry Hub NYMEX of $0.30 per Mcf for 2017. For the three and nine months ended September 30, 2016, we received cash settlements on our basis differential derivatives of approximately $1.9 million and $0.2 million, respectively.

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, 2016, refer to Part I, Item 1. Financial Statements - Note 8, “Derivative Instruments and Fair Value Measurements”.

Contractual Obligations

In addition to our capital expenditure program, we are committed to making cash payments in the future on various types of contracts and obligations. Our contractual obligations include long-term debt, operating leases, operational commitments, other loans and notes payable, derivative obligations, firm commitments under sales, gathering and processing agreements and asset retirement obligations. Since December 31, 2015, 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 7, “Long-Term Debt” for additional information on the Senior Credit Facility.

Off-Balance Sheet Arrangements

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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, 2016, 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 2016 average would reduce our gross revenues, before the effects of derivatives, for the remaining three months of 2016 by approximately $4.1 million.

56

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, 2016, we had the following commodity derivative contracts outstanding:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2016 - Collars		60,000	Bbls	$	—	$	37.50	$	49.05	$	—		$	(149	)
2016 - Three-Way Collars		60,000	Bbls		26.50		35.50		44.50		—			(328	)
2016 - Cap Swaps		30,000	Bbls		30.00		—		—		44.00			(162	)
		150,000	Bbls										$	(639	)
Natural Gas
2016 - Swaps		4,125,000	Mcf		—		—		—		2.81		$	(850	)
2016 - Swaptions		300,000	Mcf		—		—		—		3.15			(42	)
2016 - Cap Swaps		1,200,000	Mcf		2.59		—		—		3.07			(252	)
2016 - Collars		1,360,000	Mcf		—		2.59		2.99		—			(189	)
2016 - Three-Way Collars		905,000	Mcf		2.15		2.73		3.42		—			(67	)
2016 - Put Spreads		2,555,000	Mcf		2.56		3.32		—		—			341
2016 - Basis Swaps - Dominion South		2,925,000	Mcf		—		—		—		(0.90	)		1,248
2017 - Swaps		7,460,000	Mcf		—		—		—		3.09			381
2017 - Swaptions		-	Mcf		—		—		—		—			(350	)
2017 - Cap Swaps		3,900,000	Mcf		2.35		—		—		2.81			(1,345	)
2017 - Three-Way Collars		17,510,000	Mcf		2.33		3.01		3.87		—			1,253
2017 - Calls		3,000,000	Mcf		—		—		3.64		—			(939	)
2017 - Collars		1,400,000	Mcf		—		2.40		3.10		—			(267	)
2017 - Basis Swaps - Dominion South		4,550,000	Mcf		—		—		—		(0.83	)		380
2017 - Basis Swaps - Texas Gas		14,600,000	Mcf		—		—		—		(0.13	)		(602	)
2018 - Swaps		960,000	Mcf		—		—		—		3.60			573
2018 - Swaptions		-	Mcf		—		—		—		—			(164	)
2018 - Three-Way Collars		8,775,000	Mcf		2.30		2.89		3.58		—			(297	)
2018 - Calls		5,810,000	Mcf		—		—		3.97		—			(365	)
2018 - Basis Swaps - Dominion South		6,400,000	Mcf		—		—		—		(0.83	)		380
2018 - Basis Swaps - Texas Gas		14,600,000	Mcf		—		—		—		(0.13	)		(602	)
2019 - Basis Swaps - Dominion South		7,300,000	Mcf		—		—		—		(0.83	)		380
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.83	)		380
		116,955,000	Mcf										$	(1,015	)
NGLs
2016 - C3+ NGL Swaps		357,000	Bbls		—		—		—		26.22		$	(396	)
2016 - Ethane Swaps		165,000	Bbls		—		—		—		8.49			(106	)
2017 - C3+ NGL Swaps		468,000	Bbls		—		—		—		19.98			(2,455	)
2017 - Ethane Swaps		540,000	Bbls		—		—		—		10.13			(319	)
		1,530,000	Bbls										$	(3,276	)
Refined Product (Heating Oil)
2016 - Swaps		3,000	Bbls	$	—	$	—	$	—	$	84.00		$	(57	)
		3,000	Bbls										$	(57	)

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. As of September 30, 2016, we did not have any interest rate derivatives in place, however we do from time to time enter interest rate derivatives to manage our interest rate exposure. We did not have any interest rate derivatives in place as of December 31, 2015. Based on our total debt as of September 30, 2016 of approximately $759.7 million, a 1.0% change in interest rates would impact our interest expense by approximately $7.6 million.

57

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

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, 2016, 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.

Internal Control over Financial Reporting

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, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations Inherent in All Controls

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.

58

PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

The information set forth under the subsections Legal Reserves and Environmental in Note 12, 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.

Item 1A. Risk Factors.

During the quarter ended September 30, 2016, 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, 2015.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

None.

Item 5. Other Information.

None.

Item 6.Exhibits.

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.

59

SIGNATURES

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.

	REX ENERGY CORPORATION (Registrant)
Date: November 9, 2016	By:	/s/ Thomas C. Stabley
		Thomas C. Stabley
		Chief Executive Officer (Principal Executive Officer)

Date: November 9, 2016	By:	/s/ Thomas Rajan
		Thomas Rajan
		Chief Financial Officer (Principal Financial Officer)

60

EXHIBIT INDEX

Exhibit Number	Exhibit Title
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).
4.12	Indenture, dated as of March 31, 2016, among Rex Energy Corporation, the Guarantors and Wilmington Savings Fund Society, FSB, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with SEC on March 31, 2016).
4.13	Form of 1.00%/8.00% Senior Secured Second Lien Notes Due 2020 (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on March 31, 2016, and incorporated herein by reference).

61

Exhibit Number	Exhibit Title
4.14	Registration Rights Agreement, dated as of March 31, 2016, by Rex Energy Corporation and the Guarantors for the Benefit of the Holders of Rex Energy Corporation’s 1.00%/8.00% Senior Secured Second Lien Notes due 2020 (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed with SEC on March 31, 2016).
4.15	First Supplemental Indenture, dated as of March 31, 2016, to the Indenture dated as of December 12, 2012, among Rex Energy Corporation, the Guarantors, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.4 to our Current Report on Form 8-K filed with SEC on March 31, 2016).
4.16	First Supplemental Indenture, dated as of March 31, 2016, to the Indenture dated as of July 17, 2014, among Rex Energy Corporation, the Guarantors, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.5 to our Current Report on Form 8-K filed with SEC on March 31, 2016).
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

* These exhibits are filed herewith.

62