Rex Energy 8-K Rex Energy Reports Fourth Quarter and Full Year 2014

Exhibit 99.1

Rex Energy Reports Fourth Quarter and Full Year 2014

Operational and Financial Results

• Record annual average daily production of 154.4 MMcfe per day, an increase of 66% over 2013

• Total proved reserves increased 57% to 1.3 Tcfe

• Drill-bit finding and development cost of $0.67/Mcfe

• Ended 2014 with approximately $420 million of liquidity

STATE COLLEGE, Pa., February 18, 2015 (GLOBE NEWSWIRE) – Rex Energy Corporation (Nasdaq: REXX) announced its fourth quarter and full year 2014 operational and financial results.

Rex Energy had another year of successfully executing its strategy of improving performance, and increasing production and proved reserves through the drill-bit. Rigorous focus on cost control and operations has resulted in the company being among the best in the Marcellus on efficiently replacing reserves with low finding and development costs.

Production for 2014 averaged 154.4 MMcfe/d per day, a 66% increase over 2013. Fourth quarter 2014 production increased 15% over the third quarter of 2014 to 196.0 MMcfe/d per day, a record high for Rex Energy and was 78% higher than the prior year period. Oil and natural gas liquids (“NGLs”) increased 16% over the third quarter of 2014 and was also a record level for the company. Proved reserves increased 57% year-over-year to 1.3 Tcfe. Drill-bit finding and development cost averaged $0.67 per Mcfe, while drill-bit finding and development cost in the Butler Operated Area was $0.41 per Mcfe.

“I am extremely proud of our accomplishments during 2014,” said Tom Stabley, Chief Executive Officer of Rex Energy. “Over the course of the year, we achieved our goals of improving operational performance, reducing costs, and managing our balance sheet to continue targeted development of our legacy Butler Operated Area. With preliminary results from the Moraine East Development area indicating analogous performance to our legacy Butler Operated area, we are even more optimistic about our prospects and our plans for development. For 2015, our drilling plans are concentrated toward our best locations in the Appalachian Basin, and we will continue to focus on cost control and further improving our operational and capital efficiency.”

Full Year 2014 Financial Results

Operating revenues from continuing operations for the full year 2014 were $298.0 million, which represents an increase of 39% over full year 2013 operating revenues. Commodity revenues, including settlements from derivatives, were $303.8 million, an increase of 37% over full year 2013. Commodity revenues from oil and natural gas liquids (NGLs), including settlements from derivatives, represented 58% of total commodity revenues for full year 2014.

Including the effects of cash settled basis differential derivatives, the company’s basis differential for its Appalachian Basin assets average approximately ($0.87) off the average Henry Hub settlement price of $4.41 for the twelve months ended December 31, 2014.

Lease operating expenses (LOE) from continuing operations was $100.3 million for the full year 2014, or $1.78 per Mcfe. This represents a 3% decrease on a per unit basis as compared to the full year 2013.

Cash general and administrative (G&A) expenses from continuing operations, a non-GAAP measure, were $30.5 million for the full year 2014, which represents a 28% decrease on a per unit basis as compared to full year 2013.

Net loss from continuing operations attributable to common shareholders for full year 2014 was $50.0 million, or $0.94 per basic share. Adjusted net income, a non-GAAP measure, for full year 2014 was $22.1 million, or $0.42 per share.

EBITDAX from continuing operations, a non-GAAP measure, was $174.5 million for full year 2014, an increase of 31% over full year 2013.

Fourth Quarter Financial Results

Operating revenues from continuing operations for the three months ended December 31, 2014 were $70.2 million, which represents an increase of 11% over the same period in 2013. Commodity revenues, including settlements from derivatives, were $80.4 million, an increase of 24% over the comparable period of 2013. Commodity revenues from oil and natural gas liquids (NGLs), including settlements from derivatives, represented 60% of total commodity revenues for the three months ended December 31, 2014.

Including the effects of cash settled basis differential derivatives, the company’s basis differential for its Appalachian Basin assets averaged approximately ($1.26) off the average Henry Hub settlement price of $4.00 for the three months ended December 31, 2014.

LOE from continuing operations was $30.9 million, or $1.72 per Mcfe for the fourth quarter of 2014, a 5% decrease from the fourth quarter of 2013. Cash G&A expenses from continuing operations, a non-GAAP measure, were $7.5 million for the fourth quarter of 2014, a 34% decrease on a per unit basis from the fourth quarter of 2013.

The company incurred a non-cash impairment charge of approximately $132.6 million during the fourth quarter of 2014. The reduction in carrying value, which was focused in the Illinois Basin, is attributable to the recent decline in expected future prices for crude oil.

Net loss from continuing operations attributable to common shareholders for the three months ended December 31, 2014 was $71.7 million, or $1.35 per basic share. Adjusted net income, a non-GAAP measure, for the three months ended December 31, 2014 was $1.0 million, or $0.02 per share.

EBITDAX from continuing operations, a non-GAAP measure, was $42.3 million for the fourth quarter of 2014, an increase of 4% over the fourth quarter of 2013.

Reconciliations of adjusted net income to GAAP net income, EBITDAX to GAAP net income and G&A to cash G&A for the three and twelve months ended December 31, 2014, as well as a discussion of the uses of each measure, are presented in the appendix of this release.

Full Year 2014 Capital Investments

For the full year 2014, the company made operational capital investments of approximately $356.2 million, of which $317.5 million was used to fund Marcellus and Ohio Utica operations and $38.6 million was used to fund conventional drilling, water flood enhancement and facility upgrades in the Illinois Basin. The Marcellus and Ohio Utica capital investment funded the drilling of 51.0 gross (37.6 net) wells, fracture stimulation of 62.0 gross (45.5 net) wells, placing 52.0 gross (38.1 net) wells into sales and other projects related to drilling and completing wells in the Appalachian Basin.

Investments for leasing and property acquisition were $65.8 million and capitalized interest was $7.3 million for full year 2014. Capital expenditures by the company’s water service subsidiary, Keystone Clearwater Services, were $13.3 million for full year 2014.

Operational Update

Note: Unless specifically stated otherwise in this operational update, all numbers are gross and all well results assume full ethane recovery.

Appalachian Basin – Butler Operated Area

In the Butler Operated Area, the company drilled 38.0 gross (26.6 net) wells in 2014, with 38.0 gross (26.6 net) wells fracture stimulated and 34.0 gross (23.8 net) wells placed into sales. The company had 12.0 gross (8.4 net) wells drilled and awaiting completion as of December 31, 2014.

Appalachian Basin – Warrior North Prospect – Carroll County, Ohio

In the Warrior North Prospect, the company drilled six gross (6.0 net) wells in 2014, with 12 gross (12.0 net) wells fracture stimulated and 12.0 gross (12.0 net) wells placed into service.

The company is currently drilling the second well of the three-well Kiko pad, located in Carroll County, OH. The three wells on the Kiko pad are expected to be drilled to an average lateral length of approximately 5,000 feet. The three-well pad is expected to be completed in the second quarter of 2015.

Appalachian Basin – Warrior South Prospect – Guernsey, Noble & Belmont Counties

In the Warrior South Prospect, the company drilled six gross (4.6 net) wells in 2014, with six gross (4.6 net) wells fracture stimulated and six gross wells waiting to be placed into sales at year-end. These six wells, located on the J. Hall pad in Guernsey County, OH, have since been placed into sales.

The six-well J. Hall pad produced at an average 5-day sales rate per well (excluding downtime) of 1,802 boe/d (44% NGLs, 35% natural gas, 20% condensate) and an average 30-day sales rate per well (excluding downtime) of 1,364 boe/d (45% NGLs, 37% natural gas, 18% condensate).

First Quarter and Full Year 2015 Guidance

Rex Energy is providing its guidance for the first quarter and updating its full year 2015 guidance ($ in millions):

	1Q2015		Full Year 2015
Production		190.0 - 196.0		196 - 205.0 MMcfe/d
Lease Operating Expense		$29.0 -$31.0 million		—
Cash G&A(1)		$7.0 -$8.2 million		—
Operational Capital Expenditures(2)		—	$	180 - $220 million

(1) Cash G&A guidance does not include G&A expenses related to Keystone Clearwater Solutions

(2) Land acquisition expense and capitalized interest are not included in the operational capital expenditures budget

The company anticipates its first quarter 2015 production to be constrained by approximately 11.1 MMcfe/d due to involuntary production curtailments in the Company’s Butler Operated area and Warrior North Prospect related to downtime at the Enterprise Production Partners ATEX pipeline and Blue Racer compressor station. In addition, given the company’s reduced well costs in the Appalachian Basin, operating capital expenditures for full year 2015 are expected to be at the low-end of the company’s guidance range of $180 - $220 million.

Conference Call Information

Management will host a live conference call and webcast on Thursday, February 19, 2015 at 8:00 a.m. Eastern to review fourth quarter and full year 2014 financial results and operational highlights. All financial results included in this release or discussed on the conference call are preliminary pending the completion by our independent auditors of the 2014 audit. The telephone number to access the conference call is (866) 437-1772. Presentation slides containing reference materials for the call and webcast will be available on the company’s website,www.rexenergy.com, under the Investor Relations tab.

About Rex Energy Corporation

Rex Energy is headquartered in State College, Pennsylvania and is an independent oil and gas exploration and production company operating in the Appalachian Basin and Illinois Basins within the United States. The company’s strategy is to pursue its higher potential exploration drilling prospects while acquiring oil and natural gas properties complementary to its portfolio.

Forward-Looking Statements

Except for historical information, statements made in this release, including those relating to the timing and nature of development plans; drilling and completion schedules; anticipated fracture stimulation activities; expected dates for placement of wells into sales; and our financial guidance for first quarter and full year 2015 plans are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements may contain words such as “expected”, “expects”, “scheduled”, “planned”, “plans”, “anticipates” or similar words. These statements are based on management’s experience and perception of historical trends, current conditions, and anticipated future developments, as well as other factors believed to be appropriate. We believe these statements and the assumptions and estimates contained in this release are reasonable based on information that is currently available to us. However, management’s assumptions and the company’s future performance are subject to a wide range of business risks and uncertainties, both known and unknown, and we cannot assure that the company can or will meet the goals, expectations, and projections included in this release. Any number of factors could cause our actual results to be materially different from those expressed or implied in our forward looking statements, including (without limitation):

• economic conditions in the United States and globally;

• domestic and global demand for oil, NGLs and natural gas;

• volatility in oil, NGL, and natural gas pricing;

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

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

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

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

• drilling and operating 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 acquisition;

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

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

• the adequacy and availability of capital resources, credit, and liquidity including, but not limited to, access to additional borrowing capacity; and

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

The company undertakes no obligation to publicly update or revise any forward-looking statements. Further information on the company’s risks and uncertainties is available in the company’s filings with the Securities and Exchange Commission.

*    *    *    *    *

For more information, please contact:

Mark Aydin

Manager, Investor Relations

(814) 278-7249

maydin@rexenergycorp.com

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

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

	December 31, 2014 (Unaudited)			December 31, 2013
ASSETS
Current Assets
Cash and Cash Equivalents	$	17,978		$	1,307
Accounts Receivable		43,936			32,284
Taxes Receivable		504			5,189
Short-Term Derivative Instruments		29,265			5,668
Current Deferred Tax Asset		—			3,451
Assets Held for Sale		34,257			18,343
Inventory, Prepaid Expenses and Other		3,403			2,118
Total Current Assets		129,343			68,360
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,079,039			749,680
Unevaluated Oil and Gas Properties		322,413			189,385
Other Property and Equipment		46,361			58,317
Wells and Facilities in Progress		127,655			75,514
Pipelines		15,657			7,678
Total Property and Equipment		1,591,125			1,080,574
Less: Accumulated Depreciation, Depletion and Amortization		(366,917	)		(188,568	)
Net Property and Equipment		1,224,208			892,006
Deferred Financing Costs and Other Assets - Net		17,070			11,787
Equity Method Investments		17,895			18,708
Long-Term Derivative Instruments		4,904			535
Long-Term Deferred Tax Asset		8,301			—
Total Assets	$	1,401,721		$	991,396
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable		53,340		$	30,345
Current Maturities of Long-Term Debt		1,176			1,340
Accrued Liabilities		59,478			48,204
Short-Term Derivative Instruments		421			4,663
Current Deferred Tax Liability		8,301			—
Liabilities Related to Assets Held for Sale		25,115			15,461
Total Current Liabilities		147,831			100,013
8.875% Notes Due 2020		350,000			350,000
6.25% Senior Notes Due 2022		325,000			—
Premium on Senior Notes, Net		2,725			3,078
Senior Secured Line of Credit and Long-Term Debt		251			59,137
Long-Term Derivative Instruments		2,377			1,765
Long-Term Deferred Tax Liability		—			29,446
Other Deposits and Liabilities		4,018			4,992
Future Abandonment Cost		38,146			26,040
Total Liabilities	$	870,348		$	574,471
Stockholders’ Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 16,100 issued and outstanding on September 30, 2014 and 0 shares issued outstanding on December 31, 2013	$	1		$	—
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 54,174,763 shares issued and outstanding on September 30, 2014 and 54,186,490 shares issued and outstanding on December 31, 2013		54			54
Additional Paid-In Capital		617,826			456,554
Accumulated Deficit		(90,749	)		(41,725	)
Rex Energy Stockholders’ Equity		527,132			414,883
Noncontrolling Interests		4,241			2,042
Total Stockholders’ Equity		531,373			416,925
Total Liabilities and Owners’ Equity	$	1,401,721		$	991,396

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in Thousands, Except per Share Data)

	For the Three Months Ended December 31,						For the Year Ended December 31,
	2014			2013			2014			2013
OPERATING REVENUE
Oil, Natural Gas and NGL Sales	$	70,219		$	63,472		$	297,869		$	213,919
Other Revenue		26			36			118			200
TOTAL OPERATING REVENUE		70,245			63,508			297,987			214,119
OPERATING EXPENSES
Production and Lease Operating Expense		30,945			18,455			100,282			62,150
General and Administrative Expense		8,958			8,086			36,137			30,839
Loss on Disposal of Assets		176			15			644			1,602
Impairment Expense		132,577			29,658			132,618			32,072
Exploration Expense		4,556			3,897			9,446			11,408
Depreciation, Depletion, Amortization and Accretion		28,016			23,023			94,467			62,386
Other Operating Expense (Income)		131			(318	)		134			592
TOTAL OPERATING EXPENSES		205,359			82,816			373,728			201,049
INCOME (LOSS) FROM OPERATIONS		(135,114	)		(19,308	)		(75,741	)		13,070
OTHER EXPENSE
Interest Expense		(11,741	)		(6,729	)		(36,977	)		(22,676	)
Gain (Loss) on Derivatives, Net		36,561			(1,485	)		38,876			(2,908	)
Other Income		74			4,627			90			6,739
Loss on Equity Method Investments		(203	)		(194	)		(813	)		(763	)
TOTAL OTHER INCOME (EXPENSE)		24,691			(3,781	)		1,176			(19,608	)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(110,423	)		(23,089	)		(74,565	)		(6,538	)
Income Tax Benefit		41,026			9,333			26,915			4,154
LOSS FROM CONTINUING OPERATIONS		(69,397	)		(13,756	)		(47,650	)		(2,384	)
Income (Loss) From Discontinued Operations, Net of Income Taxes		767			(208	)		5,000			1,811
NET LOSS		(68,630	)		(13,964	)		(42,650	)		(573	)
Net Income Attributable to Noncontrolling Interests		699			645			4,039			1,557
NET LOSS ATTRIBUTABLE TO REX ENERGY		(69,329	)		(14,609	)		(46,689	)		(2,130	)
Preferred Stock Dividends		2,335			—			2,335			—
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(71,664	)	$	(14,609	)	$	(49,024	)	$	(2,130	)
Earnings per common share:
Basic – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(1.35	)	$	(0.26	)	$	(0.94	)	$	(0.05	)
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.00			(0.02	)		0.02			0.01
Basic – Net Loss Attributable to Rex Energy Common Shareholders	$	(1.35	)	$	(0.28	)	$	(0.92	)	$	(0.04	)
Basic – Weighted Average Shares of Common Stock Outstanding		53,261			52,705			53,150			52,572
Diluted – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(1.35	)	$	(0.26	)	$	(0.94	)	$	(0.05	)
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.00			(0.02	)		0.02			0.01
Diluted – Net Loss Attributable to Rex Energy Common Shareholders	$	(1.35	)	$	(0.28	)	$	(0.92	)	$	(0.04	)
Diluted – Weighted Average Shares of Common Stock Outstanding		53,261			52,705			53,150			52,572

REX ENERGY CORPORATION

CONSOLIDATED OPERATIONAL HIGHLIGHTS

UNAUDITED

	Three Months Ending December 31,					Year Ending December 31,
	2014		2013			2014		2013
Oil, Natural Gas, NGL and Ethane sales (in thousands):
Oil and condensate sales	$	22,019	$	23,330		$	97,426	$	86,959
Natural gas sales		29,119		25,336			126,500		87,078
Natural gas liquid sales (C3+)		16,731		14,806			69,626		39,882
Ethane sales		2,350		—			4,317		—
Cash-settled derivatives:
Crude oil		2,707		(758	)		1,085		(3,495	)
Natural gas		3,181		3,054			1,637		10,885
Natural gas liquids (C3+)		4,291		(709	)		3,247		(263	)
Total oil, gas, NGL and Ethane sales including cash settled derivatives	$	80,398	$	65,059		$	303,838	$	221,046
Production during the period:
Oil and condensate (Bbls)		332,749		249,975			1,141,106		914,232
Natural gas (Mcf)		11,329,490		7,033,238			37,011,177		23,446,755
Natural gas liquids (C3+) (Bbls)		488,753		270,111			1,531,131		819,670
Ethane (Bbls)		294,810		—			551,315		—
Total (Mcfe)a		18,027,362		10,153,754			56,352,489		33,850,167
Production – average per day:
Oil and condensate (Bbls)		3,617		2,717			3,126		2,505
Natural gas (Mcf)		123,147		76,448			101,400		64,238
Natural gas liquids (C3+) (Bbls)		5,313		2,936			4,195		2,246
Ethane (Bbls)		3,204		—			1,510		—
Total (Mcfe)a		195,951		110,366			154,386		92,744
Average price per unit:
Realized crude oil price per Bbl – as reported	$	66.17	$	93.33		$	85.38	$	95.12
Realized impact from cash settled derivatives per Bbl		8.14		(3.03	)		0.95		(3.82	)
Net realized price per Bbl	$	74.31	$	90.30		$	86.33	$	91.30
Realized natural gas price per Mcf – as reported	$	2.57	$	3.60		$	3.42	$	3.71
Realized impact from cash settled derivatives per Mcf		0.28		0.43			0.04		0.46
Net realized price per Mcf	$	2.85	$	4.03		$	3.46	$	4.17
Realized natural gas liquids (C3+) price per Bbl – as reported	$	34.23	$	54.81		$	45.47	$	48.66
Realized impact from cash settled derivatives per Bbl		8.78		(2.62	)		2.12		(0.32	)
Net realized price per Bbl	$	43.01	$	52.19		$	47.59	$	48.34
Realized ethane price per Bbl – as reported	$	7.97	$	—		$	7.83	$	—
Realized impact from cash settled derivatives per Bbl		—		—			—		—
Net realized price per Bbl	$	7.97	$	—		$	7.83	$	—
LOE/Mcfe	$	1.72	$	1.82		$	1.78	$	1.84
Cash G&A/Mcfe	$	0.42	$	0.64		$	0.54	$	0.75

^a  Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent to six Mcfe.

REX ENERGY CORPORATION

COMMODITY DERIVATIVES – HEDGE POSITION AS OF 2/6/2015

	2015			2016
Oil Derivatives (Bbls)
Swap Contracts
Volume		25,000	(1)		—
Price	$	95.76		$	—
Collar Contracts
Volume		190,000			60,000
Ceiling	$	62.82		$	63.81
Floor	$	52.50		$	53.75
Collar Contracts with Short Puts
Volume		575,000			—
Ceiling	$	73.80		$	—
Floor	$	66.20		$	—
Short Put	$	51.41		$	—
Put Spread Contracts
Volume		150,000			120,000
Floor	$	83.33		$	65.00
Short Put	$	73.08		$	50.00
Natural Gas Derivatives (Mcf)
Swap Contracts
Volume		19,225,000	(2)		8,220,000	(3)
Price	$	3.80		$	3.94
Swaption Contracts
Volume		2,750,000			—
Price	$	3.54		$	—
Put Spread
Volume		1,050,000			—
Floor	$	4.05		$	—
Short Put	$	3.60		$	—
Collar Contracts with Short Puts
Volume		12,900,000			9,300,000
Ceiling	$	4.22		$	4.30
Floor	$	3.56		$	3.45
Short Put	$	2.89		$	2.71
Call Contracts
Volume		3,250,000			9,120,000
Ceiling	$	4.00		$	4.23
Natural Gas Liquids (Bbls)
Swap Contracts
Propane (C3)
Volume		623,000			45,000
Price	$	29.82		$	20.58
Butane (C4)
Volume		85,000			—
Price	$	29.69		$	—
Isobutane (IC4)
Volume		42,000			—
Price	$	30.32		$	—
Natural Gasoline (C5+)
Volume		55,000			—
Price	$	45.15		$	—
Ethane
Volume		320,200			—
Price	$	8.40			—
Natural Gas Basis (Mcf)
Swap Contracts
Dominion Appalachia
Volume		10,180,000			7,320,000
Price	$	(0.78	)	$	(0.83	)

⁽¹⁾ Includes 25,000 Bbls of call-protected swaps

⁽²⁾ Includes 7.7 Bcf of enhanced swaps

⁽³⁾  Includes 3.6 Bcf of enhanced swaps

⁽⁴⁾  Financial derivatives only

APPENDIX

REX ENERGY COPRORATION

NON-GAAP 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, non-recurring gains and losses, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives and gains on asset dispositions, 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.

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.

For purposes of consistency with current calculations, we have revised certain amounts relating to prior period EBITDAX. The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented ($ in thousands):

	Three Months Ended December 31,						Year Ended December 31,
	2014			2013			2014			2013
Loss From Continuing Operations	$	(69,397	)	$	(13,756	)	$	(47,650	)	$	(2,384	)
(Gain) Loss on Derivatives, Net		(36,561	)		1,485			(38,876	)		2,908
Realized Gain on Derivatives		10,612			1,588			7,281			7,128
Add Back (Less) Unrealized (Gain) Loss from Financial Derivatives		(25,949	)		3,073			(31,595	)		10,036
Add Back Depletion, Depreciation, Amortization and Accretion		28,016			23,023			94,467			62,386
Add Back Non-Cash Compensation Expense		1,427			1,596			5,672			5,384
Add Back Interest Expense		11,741			6,729			36,977			22,676
Add Back Impairment Expense		132,577			29,658			132,618			32,072
Add Back Exploration Expenses		4,556			3,897			9,446			11,408
Add Back (Less) Loss (Gain) on Disposal of Assets(1)		176			(4,539	)		644			(5,204	)
Less Income Tax Benefit		(41,026	)		(9,333	)		(26,915	)		(4,154	)
Add Back Non-Cash Portion of Equity Method Investment		202			197			805			752
EBITDAX From Continuing Operations	$	42,323		$	40,545		$	174,469		$	132,972
Income (Loss) From Discontinued Operations, Net of Income Taxes		767			(208	)		5,000			1,810
Net Income Attributable to Noncontrolling Interests		(699	)		(645	)		(4,039	)		(1,557	)
Income (Loss) From Discontinued Operations Attributable to Rex Energy		68			(853	)		961			253
Add Back Depletion, Depreciation, Amortization and Accretion		1,141			554			3,703			1,559
Add Back Interest Expense		147			40			629			106
Add Back Impairment Expense		67			—			67			—
Add Back Exploration Expenses		—			—			—			97
Add Back (Less) Loss (Gain) on Disposal of Assets		29			—			(55	)		(924	)
Less Non-Cash Portion of Noncontrolling Interests		(554	)		(227	)		(1,738	)		(631	)
Add Back Income Tax Expense		287			618			768			1,374
Add EBITDAX From Discontinued Operations	$	1,185		$	132		$	4,335		$	1,834
EBITDAX (Non-GAAP)	$	43,508		$	40,677		$	178,804		$	134,806

(1) Includes gain on sale of Keystone Midstream Services, LLC of approximately $4.6 million for the three months ended December 31, 2013 and $6.9 million for the year ended December 31, 2013

Adjusted Net Income

“Adjusted Net Income” means, for any period, the sum of net income for the period plus the following expenses, charges or income, in each case, to the extent deducted from or added to net income in the period: unrealized losses from financial derivatives, non-cash compensation expense, dry hole expenses, disposals of assets, impairment and other one-time or non-recurring charges, minus all gains from unrealized financial derivatives, disposal of assets and deferred income tax benefits, added to net income. Adjusted Net Income is used as a financial measure by Rex Energy’s management team and by other users of its financial statements, to analyze its financial performance without regard to non-cash deferred taxes and non-cash unrealized losses or gains from oil and gas derivatives. Adjusted Net Income is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring the company’s performance.

Rex Energy reports Adjusted Net Income because it believes that this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance. You should carefully consider the specific items included in the company’s computation of this measure. You are cautioned that Adjusted Net Income as reported by Rex Energy may not be comparable in all instances to that reported by other companies.

To compensate for these limitations, the company believes it is important to consider both net income determined under GAAP and Adjusted Net Income.

The following table presents a reconciliation of Rex Energy’s net income from continuing operations to its adjusted net income for each of the periods presented ($ in thousands):

	For the Three Months Ended December 31,						For the Year Ended December 31,
	2014			2013			2014			2013
Loss From Continuing Operations Before Income Taxes, as reported	$	(110,423	)	$	(23,089	)	$	(74,565	)	$	(6,538	)
(Gain) Loss on Derivatives, Net		(36,561	)		1,485			(38,876	)		2,908
Realized Gain on Derivatives		10,612			1,588			7,281			7,128
Add Back (Less) Unrealized (Gain) Loss from Financial Derivatives		(25,949	)		3,073			(31,595	)		10,036
Add Back Impairment Expense		132,577			29,658			132,618			32,072
Add Back Dry Hole Expense		3,827			2,508			4,138			3,005
Add Back Non-Cash Compensation Expense		1,427			1,596			5,672			5,384
Add Back (Less) (Gain) Loss on Disposal of Assets(1)		176			(4,539	)		644			(5,204	)
Income Before Income Taxes, adjusted	$	1,635		$	9,207		$	36,912		$	38,755
Less Income Taxes, adjusted(2)		(654	)		(3,683	)		(14,765	)		(15,502	)
Adjusted Net Income	$	981		$	5,524		$	22,147		$	23,253
Basic – Adjusted Net Income Per Share	$	0.02		$	0.10		$	0.42		$	0.44
Basic – Weighted Average Shares of Common Stock Outstanding		53,261			52,705			53,150			52,572

(1) Includes gain on sale of Keystone Midstream Services, LLC of approximately $4.6 million for the three months ended December 31, 2013 and $6.9 million for the years ended December 31, 2013

(2) Assumes tax rate of 40%

Cash General and Administrative Expenses

Cash General and Administrative Expenses (Cash G&A) is the difference between GAAP G&A and non-Cash G&A, which is primarily comprised of non-cash compensation expense. Rex Energy has reported Cash G&A because it believes that this measure is commonly reported and widely used by management and investors as an indicator of overhead efficiency without regard to non-cash expenditures, such as stock compensation. Cash G&A is not a calculation based on GAAP financial measures and should not be considered as an alternative to GAAP G&A in measuring the company’s performance. You should carefully consider the specific items included in the company’s computation of this measure. You are cautioned that Cash G&A as reported by Rex Energy may not be comparable in all instances to that reported by other companies.

To compensate for these limitations, the company believes it is important to consider both Cash G&A and GAAP G&A. The following table presents a reconciliation of Rex Energy’s GAAP G&A to its Cash G&A for each of the periods presented (in thousands):

	Three Months Ended December 31,						Year Ended December 31,
	2014			2013			2014			2013
GAAP G&A	$	8,958		$	8,086		$	36,137		$	30,839
Non-Cash Compensation Expense		(1,427	)		(1,596	)		(5,672	)		(5,384	)
Cash G&A	$	7,531		$	6,490		$	30,465		$	25,455