• Improved well design in Warrior North results in increased EURs and rate of returns
• In Warrior North, placed four-well Vaughn pad into sales; 5-day average sales rate per well of 1.5 Mboe/d and 65% liquids
• Liquids production accounted for 44% of total commodity revenues for the fourth quarter of 2016
• Realized C3+ NGL pricing for fourth quarter of 2016 was 56% of WTI before hedging
• Increased 2017 realized C3+ NGL pricing, before hedging, to 50% - 55% of WTI oil prices
• Production from continuing operations for the fourth quarter of 2016 was 194.9 MMcfe/d, a 12% year-over-year increase, including 38% from liquids
• 2016 net operational capital expenditures of $29.5 million came in below previous expectations of $35.5 million

STATE COLLEGE, Pa., March 07, 2017 (GLOBE NEWSWIRE) -- Rex Energy Corporation (Nasdaq:REXX) today announced its fourth quarter and full-year 2016 operational and financial results.

Operational Update

Warrior North Area

In the Warrior North Area, the company drilled seven gross (2.5 net) wells in 2016, with ten gross (4.1 net) wells fracture stimulated and 13 gross (5.1 net) wells placed into sales. The company had no wells drilled and awaiting completion as of December 31, 2016.

The company recently placed the four-well Vaughn pad into sales. The Vaughn wells were drilled to an average lateral length of approximately 7,200 feet and completed in an average of 37 stages with average sand concentrations of 2,600 pounds per foot. The wells produced at an average 24-hour sales rate per well, assuming full ethane recovery, of 1.5 Mboe/d, consisting of 3.1 MMcf/d of natural gas, 639 bbls/d of NGLs and 315 bbls/d of condensate. The wells went on to produce an average 5-day sales rate per well, assuming full ethane recovery, of 1.3 Mboe/d, consisting of 2.8 MMcf/d of natural gas, 579 bbls/d of NGLs and 289 bbls/d of condensate. The four Vaughn wells were drilled on the eastern portion of the Warrior North Area, where condensate yields have historically been lower than seen in other areas of the field.

Warrior North - Well Level Economics / Type Curve Update

The company has updated its well-level economics for the Warrior North Area. In the Warrior North Area, the company has adjusted its well-level economics to reflect its increased average lateral length, strong well performance, reduced cycle times and adjustments in expected realized prices. In summary, the rate of return assuming a $3.00Henry Hub natural gas index price and $55.00 WTI oil index price has increased from 28% to 47% in the Warrior North Area. In addition, several of the company's most recent Warrior North wells are performing above the company's year-end 2016 type curve for the Warrior North Area. The updated results, as well as a comparison to previous results, are included on slide 23 of the company's updated March corporate presentation.

Legacy Butler Operated Area

In the Legacy Butler Operated Area, the company drilled two gross (1.4 net) wells in 2016, with two gross (1.4 net) wells fracture stimulated and two gross (1.4 net) wells placed into sales. The company had no wells drilled and awaiting completion as of December 31, 2016.

In 2017, the company plans to drill the four-well Wilson pad in the Legacy Butler Operated Area, with an estimated average lateral length of 9,200 feet. The four-well Wilson pad is adjacent to the two-well Geyer pad, which was drilled to an average lateral length of 4,200 feet and placed into sales in August 2016. The two-well Geyer pad had an average 5-day sales rate per well of approximately 7.1 MMcfe/d. The four wells on the Wilson pad are expected to be placed into sales in the third quarter of 2017.

Moraine East Area

In the Moraine East Area, the company drilled 11.0 gross (4.5 net) wells in 2016, with six gross (2.7 net) wells fracture stimulated and 18 gross (8.7 net) wells placed into sales. The company had nine gross (3.8 net) wells drilled and awaiting completion as of December 31, 2016.

The company recently finished completing the four-well Baird pad, which was drilled to an average lateral length of approximately 7,140 feet. The pad is expected to be placed into sales at the end of the first quarter of 2017. The company has also finished drilling the six-well Shields pad, which was drilled to an average lateral length of approximately 7,750 feet. The Shields pad is expected to be placed into sales in the third quarter of 2017. The company is currently drilling the third of four wells on the Mackrell pad, which is expected to be drilled to an average lateral length of approximately 7,630 feet. The Mackrell pad is expected to be placed into sales in second half of 2017.

The six-well Shields pad and the four-well Mackrell pad will be the first wells drilled on the eastern portion of the Moraine East Area. This area is characterized by a thicker Upper Marcellus formation and the brittle nature of the formation allows for more effective completions. In addition, the Shields pad and the Mackrell pad are on trend with the the two-well Lynn pad, which was drilled in the Legacy Butler perated Area. The two wells were drilled to an average lateral length of approximately 2,725 feet and had average 5-day sales rates per well of 6.9 MMcfe/d.

2017 C3+ Natural Gas Liquids Pricing Improvement

During the fourth quarter of 2016, realized C3+ NGL prices, before the effects of hedging, averaged approximately 56% of WTI oil prices. The improvement in pricing was driven largely by the recent improvement in Mont Belvieu prices as well as improved differentials for NGLs in the northeast. Due to these improvements, the company now expects full-year 2017 realized C3+ NGL prices to average approximately 50% - 55% of WTI, an improvement over the previous guidance of 43% - 48%.

Fourth Quarter Financial Results

Unless otherwise noted, results of continuing operations are presented excluding the results of the company's Illinois Basin assets, which have been classified as discontinued operations, for all periods presented. Fourth quarter and full-year 2016 production includes approximately 9.0 MMcfe/d related to the company's recently divested Warrior South assets.

Operating revenue from continuing operations for the three months ended December 31, 2016 was $48.0 million, which represents an increase of 75% as compared to the same period in 2015. Commodity revenues, including settlements from derivatives, were $48.2 million, an increase of 12% as compared to the same period in 2015. Commodity revenues from natural gas liquids (NGLs) and condensate, including settlements from derivatives, represented 44% of total commodity revenues for the three months ended December 31, 2016.

Lease operating expense (LOE) from continuing operations was $28.7 million, or $1.60 per Mcfe for the quarter, a 15% increase as compared to the fourth quarter of 2015. The increase on a per unit basis is related to the commencement of the company's Gulf Coast transportation during the fourth quarter of 2016 which was partially offset by decreased natural gas basis differentials. General and administrative expenses from continuing operations were $5.4 million for the fourth quarter of 2016, a 25% decrease on a per unit basis as compared to the same period in 2015. Cash general and administrative expenses from continuing operations, a non-GAAP measure, were $4.3 million for the fourth quarter of 2016, a 25% decrease on a per unit basis as compared to the same period in 2015.

Full-Year 2016 Financial Results

Operating revenue from continuing operations for full-year 2016 were $139.0 million, which remained flat as compared to 2015 operating revenue. Commodity revenue, including settlements from derivatives, were $171.9 million, a decrease of 11% from full-year 2015. Commodity revenue from natural gas liquids (NGLs) and condensate, including settlements from derivatives, represented 42% of total commodity revenues for full-year 2016.

LOE from continuing operations was $104.7 million, or $1.46 per Mcfe for 2016, a 4% year-over-year increase on a per unit basis as compared to full-year 2015. The increase is due to the commencement of the company's Gulf Coast transportation during the fourth quarter of 2016. The increase in per unit LOE was partially offset by the decrease in natural gas basis differentials related to the Gulf Coast transport. General and administrative expenses from continuing operations were $20.6 million for full-year 2016, a 28% decrease on per unit basis as compared to full-year 2015. Cash general and administrative expenses from continuing operations, a non-GAAP measure, were $17.5 million for full-year 2016, a 19% decrease on per unit basis as compared to full-year 2015.

Reconciliations of G&A to cash G&A for the three months and twelve months ended December 31, 2016, as well as a discussion of the uses of this measure, are presented in the appendix of this release.

Production Results and Price Realizations

Fourth quarter 2016 production volumes from continuing operations were 194.9 MMcfe/d, an increase of 12% over the fourth quarter of 2015, consisting of 120.9 MMcf/d of natural gas, 5.4 MBbls/d of C3+ NGLs, 5.8 Mbbls/d of ethane and 1.1 Mbbls/d of condensate. NGLs (including ethane) and condensate accounted for 38% of net production for the fourth quarter of 2016. For full-year 2016, production volumes increased by 6% over 2015 to 195.3 MMcfe/d, consisting of 122.1 MMcf/d of natural gas, 5.5 MBbls/d of C3+ NGLs, 5.8 Mbbls/d of ethane and 1.0 Mbbls/d of condensate. NGLs (including ethane) and condensate accounted for 37% of net production during 2016.

Including the effects of cash-settled derivatives, realized prices for the three months ended December 31, 2016 were $2.42 per Mcf for natural gas, $25.39 per barrel for NGLs (C3+), $8.88 per barrel for ethane and $37.73 per barrel for condensate. Before the effects of hedging, realized prices for the three months ended December 31, 2016 were $2.23 per Mcf for natural gas, $27.64 per barrel for NGLs (C3+), $9.36 per barrel for ethane and $43.13 per barrel for condensate.

Including the effects of cash-settled derivatives, realized prices for the twelve months ended December 31, 2016 were $2.23 per Mcf for natural gas, $20.43 per barrel for NGLs (C3+), $7.80 per barrel for ethane and $41.64 per barrel for condensate. Before the effects of hedging, realized prices for the twelve months ended December 31, 2016 were $1.64 per Mcf for natural gas, $17.97 per barrel for NGLs (C3+), $7.81 per barrel for ethane and $37.08 per barrel for condensate.

Full-Year 2016 Capital Investments

For the full-year 2016, net operational capital investments were approximately $29.5 million. These capital investments funded the drilling of 20.0 gross (8.4 net) wells, fracture stimulation of 18.0 gross (8.2 net) wells, placing 34.0 gross (16.2 net) wells into sales and other projects related to drilling and completing wells in the Appalachian Basin.

Liquidity Update

During the first quarter of 2017, Rex Energy completed the sale of its Warrior South asset for approximately $30 million; in conjunction with the completion of the sale, the company received approval from its bank lenders to maintain the existing $190 million borrowing base. With the additional liquidity from the sale of the Warrior South asset, the company was able to add additional wells to the Shields pad and the Wilson pads. The Shields pad and the Wilson pad are targeting the highest quality areas of the Moraine East Area and the Legacy Butler Operated Area. The additional wells per pad will add to greater efficiencies to the overall well pad costs.

First Quarter and Full-Year 2017 Guidance

The following table outlines Rex Energy's guidance for the first quarter of 2017 and full-year 2017. First quarter 2017 production, adjusting for the Warrior South asset sale, would have been approximately 182.0 - 184.0 MMcfe/d. However, the company experienced delays in the completion of the four-well Vaughn pad and the four-well Baird pad during the first quarter of 2017, which resulted in a reduction of 5% to the company's expected first quarter 2017 production. Given that the majority of the wells in the 2017 development plan will be placed into sales in the second half of the year, the company continues to expect full-year 2017 average daily production to be in the range of 194.0 - 204.0 MMcfe/d. 

	1Q2017	Full-Year 2017
Production	173.0 - 175.0 MMcfe/d	194.0 - 204.0 MMcfe/d
LOE ($/Mcfe)	--	$1.70 - $1.80
Cash G&A ($/Mcfe)	--	$0.20 - $0.25
Net Operational Capital Expenditures(1)	--	$70.0 - $80.0 million
(1) Land acquisition expense and capitalized interest are not included in the net operational capital expenditures budget estimate

Conference Call Information

Management will host a live conference call and webcast on Wednesday, March 8, 2017 at 10:00 a.m. Eastern to review fourth quarter and full year 2016 financial results and operational highlights. The telephone number to access the conference call is (866) 437-1772.

About Rex Energy Corporation

Headquartered in State College, Pennsylvania, Rex Energy is an independent oil and gas exploration and production company with its core operations in the Appalachian Basin. 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; anticipated hedging strategies and potential results thereof; and our financial guidance for full year 2017, 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, and 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 supply and demand for oil, 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 meeting working capital needs;
• our ability to comply with restrictions imposed by our senior credit facility and other existing and future financing arrangements;
• our ability to service our outstanding indebtedness
• impairments of our natural gas and oil asset values due to declines in commodity prices;
• conditions in the domestic and global capital and credit markets and their effect on us;
• 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, NGL 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, 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;
• our ability to cure the deficiencies with respect to the continued listing standards of The NASDAQ Capital Market or any other exchange on which our securities trade; and
• other factors discussed under "Item 1A. Risk Factors" in our Annual Report on Form 10-K and any updates to those Risk Factors.

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on the company's risks and uncertainties is available in our filings with the Securities and Exchange Commission and we strongly encourage investors to review those filings.

REX ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
($ in Thousands, Except Share and Per Share Data)
ASSETS	December 31, 2016 (Unaudited)				December 31, 2015
Current Assets
Cash and Cash Equivalents	$	3,697			$	1,091
Accounts Receivable	25,448				17,274
Taxes Receivable	211				18
Short-Term Derivative Instruments	1,873				34,260
Inventory, Prepaid Expenses and Other	2,546				3,059
Assets Held for Sale	--				53,151
Total Current Assets	33,775				108,853
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties	1,053,461				943,092
Unevaluated Oil and Gas Properties	215,794				262,992
Other Property and Equipment	21,401				20,363
Wells and Facilities in Progress	21,964				141,100
Pipelines	18,029				14,024
Total Property and Equipment	1,330,649				1,381,571
Less: Accumulated Depreciation , Depletion and Amortization	(475,205		)		(430,528		)
Net Property and Equipment	855,444				951,043
Other Assets	2,492				2,501
Long-Term Derivative Instruments	2,212				9,534
Total Assets	$	893,923			$	1,071,931
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	40,712			$	36,785
Current Maturities of Long-Term Debt	764				402
Accrued Liabilities	37,207				40,608
Short-Term Derivative Instruments	25,025				2,486
Liabilities Related to Assets Held for Sale	--				36,320
Total Current Liabilities	103,708				116,601
Long-Term Derivative Instruments	7,227				5,556
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs	113,785				109,386
Senior Notes, Net of Issuance Costs and Deferred Gain on Debt Exchanges	641,762				663,089
Premium on Senior Notes, Net	(3,601		)		2,344
Other Long-Term Debt	3,409
Other Deposits and Liabilities	8,671				3,156
Future Abandonment Cost	8,736				11,568
Total Liabilities	$	883,697			$	911,700
Stockholder Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987 issued and outstanding on December 31, 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 97,870,608 shares issued and outstanding on December 31, 2016 and 55,741,229 shares issued and outstanding on December 31, 2015	95				54
Additional Paid-In Capital	650,584				623,863
Accumulated Deficit	(640,454		)		(463,687		)
Total Stockholders' Equity	10,226				160,231
Total Liabilities and Owners' Equity	$	893,923			$	1,071,931

REX ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in Thousands, Except per Share Data)
	For the Three Months Ended December 31,								For the Twelve Months Ended December 31,
	2016				2015				2016				2015
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	48,022			$	27,363			$	139,000			$	138,707
Other Revenue	5				12				17				42
TOTAL OPERATING REVENUE	48,027				27,375				139,017				138,749
OPERATING EXPENSES
Production and Lease Operating Expense	28,694				22,246				104,699				93,892
General and Administrative Expense	5,384				6,441				20,621				26,694
(Gain) Loss on Disposal of Assets	164				(7		)		(4,121		)		(540		)
Impairment Expense	29,275				73,364				74,619				283,244
Exploration Expense	224				843				2,178				2,617
Depreciation, Depletion, Amortization and Accretion	16,503				18,475				62,874				85,844
Other Operating Expense (Income)	(176		)		275				10,754				5,603
TOTAL OPERATING EXPENSES	80,068				121,637				271,624				497,354
LOSS FROM OPERATIONS	(32,041		)		(94,262		)		(132,607		)		(358,605		)
OTHER INCOME (EXPENSE)
Interest Expense	(9,404		)		(11,706		)		(43,519		)		(47,783		)
Gain (Loss) on Derivatives, Net	(24,261		)		14,689				(32,515		)		60,176
Other Expense	(2,152		)		(247		)		(2,124		)		(129		)
Debt Exchange Expense	(15		)		--				(9,063		)		--
Gain on Extinguishment of Debt	497				--				24,627				--
Loss on Equity Method Investments	--				--				--				(411		)
TOTAL OTHER INCOME (EXPENSE)	(35,335		)		2,736				(62,594		)		11,853
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(67,376		)		(91,526		)		(195,201		)		(346,752		)
Income Tax Expense	(8,221		)		(6,030		)		(2,436		)		(6,030		)
NET LOSS FROM CONTINUING OPERATIONS	(75,597		)		(97,556		)		(197,637		)		(352,782		)
Income (Loss) From Discontinued Operations, Net of Income Taxes	8,203				(481		)		20,922				(8,251		)
NET LOSS	(67,394		)		(98,037		)		(176,715		)		(361,033		)
Net Income Attributable to Noncontrolling Interests	--				--				--				2,245
NET LOSS ATTRIBUTABLE TO REX ENERGY	(67,394		)		(98,037		)		(176,715		)		(363,278		)
Preferred Stock Dividends	(650		)		(2,415		)		(5,091		)		(9,660		)
Effect of Preferred Stock Conversions	668				--				72,984				--
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(67,376	)		$	(100,452	)		$	(108,822	)		$	(372,938	)
Earnings per common share:
Basic - Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(0.78	)		$	(1.84	)		$	(1.63	)		$	(6.66	)
Basic - Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders	0.09				(0.01		)		0.26				(0.19		)
Basic - Net Loss Attributable to Rex Energy Common Shareholders	$	(0.69	)		$	(1.85	)		$	(1.37	)		$	(6.85	)
Basic - Weighted Average Shares of Common Stock Outstanding	97,398				54,342				79,256				54,392
Diluted - Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(0.78	)		$	(1.84	)		$	(1.63	)		$	(6.66	)
Diluted - Net Income (Loss) From Discontinued Operations Attributable to Rex Energy  Common Shareholders	0.09				(0.01		)		0.26				(0.19		)
Diluted - Net Loss Attributable to Rex Energy Common Shareholders	$	(0.69	)		$	(1.85	)		$	(1.37	)		$	(6.85	)
Diluted - Weighted Average Shares of Common Stock Outstanding	97,398				54,342				79,256				54,392

REX ENERGY CORPORATION
CONSOLIDATED OPERATIONAL HIGHLIGHTS
UNAUDITED
		Three Months Ending							Twelve Months Ending
		December 31,							December 31,
		2016				2015			2016					2015
Oil, Natural Gas, NGL and Ethane sales (in thousands):
Natural gas sales		$	24,844			$	15,083			$	73,275			$	83,140
Natural gas liquids (C3+) sales			13,824				7,917				35,877				32,789
Ethane sales			4,989				2,552				16,484				8,710
Condensate sales			4,366				1,811				13,364				14,068
Cash-settled derivatives:
Natural gas			2,068				9,323				26,348				32,573
Natural gas liquids (C3+)			(1,126	)			3,204				4,914				10,384
Ethane			(255	)			1,103				(14	)			42
Condensate			(547	)			3,054				1,644				11,860
Total oil, gas, NGL and Ethane sales including cash settled derivatives		$	48,163			$	43,054			$	171,892			$	193,566
Production during the period:
Natural gas (Mcf)			11,125,475				10,446,424				44,684,571				44,606,753
Natural gas liquids (C3+) (Bbls)			500,114				454,963				1,996,075				2,026,321
Ethane (Bbls)			532,841				416,496				2,111,321				1,319,582
Condensate (Bbls)			101,239				57,141				360,384				402,867
Total (Mcfe)1			17,930,639				16,018,024				71,491,251				67,099,373
Production - average per day:
Natural gas (Mcf)			120,929				113,548				122,089				122,210
Natural gas liquids (C3+) (Bbls)			5,436				4,945				5,454				5,552
Ethane (Bbls)			5,792				4,527				5,769				3,615
Condensate (Bbls)			1,100				621				985				1,104
Total (Mcfe)1			194,898				174,109				195,331				183,834
Average price per unit:
Realized natural gas price per Mcf - as reported		$	2.23			$	1.44			$	1.64			$	1.86
Realized impact from cash settled derivatives per Mcf			0.19				0.89				0.59				0.73
Net realized price per Mcf		$	2.42			$	2.33			$	2.23			$	2.59
Realized NGL (C3+) price per Bbl - as reported		$	27.64			$	17.40			$	17.97			$	16.18
Realized impact from cash settled derivatives per Bbl2			(2.25	)			7.04				2.46				5.12
Net realized price per Bbl		$	25.39			$	24.44			$	20.43			$	21.30
Realized ethane price per Bbl - as reported		$	9.36			$	6.13			$	7.81			$	6.60
Realized impact from cash settled derivatives per Bbl			(0.48	)			0.26				(0.01	)			0.10
Net realized price per Bbl		$	8.88			$	6.39			$	7.80			$	6.70
Realized condensate price per Bbl - as reported		$	43.13			$	31.69			$	37.08			$	34.92
Realized impact from cash settled derivatives per Bbl			(5.40	)			53.45				4.56				29.44
Net realized price per Bbl		$	37.73			$	85.14			$	41.64			$	64.36
LOE/Mcfe		$	1.60			$	1.39			$	1.46			$	1.40
Cash G&A/Mcfe		$	0.24			$	0.32			$	0.25			$	0.31
1 Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent to six Mcfe.
2  Includes the effect of derivatives not classified as discontinued operations

REX ENERGY CORPORATION
COMMODITY DERIVATIVES - HEDGE POSITION AS OF 3/2/2017
		2017				2018
Oil Derivatives (Bbls)
Swap Contracts
Volume		81,000				60,000
Price	$	53.30			$	54.00
Deferred Premium Puts
Volume		15,000				--
Floor	$	51.00				--
Collar Contracts
Volume		48,000				18,000
Ceiling	$	57.20			$	60.00
Floor	$	45.00			$	53.00
Collar Contracts with Short Puts
Volume		93,000				60,000
Ceiling	$	61.50			$	62.30
Floor	$	49.68			$	52.00
Short Put	$	40.16			$	43.00
Natural Gas Derivatives (Mcf)
Swap Contracts
Volume		14,900,000				9,160,000
Price	$	3.03			$	3.19
Swaption Contracts
Volume		2,400,000				--
Price	$	3.33			$	--
Put Spread Contracts
Volume		--				--
Floor	$	--			$	--
Short Put	$	--			$	--
Collar Contracts with Short Puts
Volume		17,510,000				8,775,000
Ceiling	$	3.87			$	3.58
Floor	$	3.01			$	2.89
Short Put	$	2.33			$	2.30
Call Contracts
Volume		8,380,100				16,489,900
Ceiling	$	4.51			$	4.64
Collar Contracts
Volume		1,700,000				450,000
Ceiling	$	3.20			$	3.65
Floor	$	2.54			$	3.20
Natural Gas Liquids (Bbls)
Swap Contracts
Propane (C3)
Volume		962,000				600,000
Price	$	23.25			$	25.56
Butane (C4)
Volume		240,000				180,000
Price	$	29.15			$	32.97
Isobutane (IC4)
Volume		117,000				96,000
Price	$	29.94			$	33.71
Natural Gasoline (C5+)
Volume		364,000				192,000
Price	$	48.01			$	49.35
Ethane
Volume		840,000				420,000
Price	$	10.47			$	13.02
Natural Gas Basis (Mcf)
Swap Contracts
Dominion Appalachia
Volume		15,435,000				18,980,000
Price	$	(0.86	)		$	(0.82	)
Texas Gas Zone 1
Volume		14,600,000				14,600,000
Price	$	(0.13	)		$	(0.13	)
NYMEX Heating Oil (Gallon)
Swap Contracts
Volume		--				--
Price	$	--			$	--

APPENDIX  
REX ENERGY CORPORATION
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.

		Three Months Ended December 31, (Unaudited)								Twelve Months Ended December 31,  (Unaudited)
		2016				2015				2016				2015
Net Loss From Continuing Operations		$	(75,597	)		$	(97,556	)		$	(197,637	)		$	(352,782	)
Add Back (Less) Non-Recurring Costs (Income)1		(372		)		--				(6,760		)		4,774
Add Back Depletion, Depreciation, Amortization and Accretion		16,503				18,475				62,874				85,844
Add Back Non-Cash Compensation Expense		1,072				1,378				3,078				5,791
Add Back Interest Expense		9,404				11,706				43,519				47,783
Add Back Impairment Expense		29,275				73,364				74,619				283,244
Add Back Exploration Expenses		224				843				2,178				2,617
Add Back (Less) (Gain) Loss on Disposal of Assets2		164				(4		)		(4,121		)		(537		)
Add Back (Less) (Gain) Loss on Financial Derivatives		24,261				(14,689		)		32,515				(60,176		)
Add Back Cash Settlement of Derivatives		86				15,691				32,571				55,793
Add Back Non-Cash Portion of Equity Method Investments		--				--				--				406
Add Back Income Tax Expense		8,221				6,030				2,436				6,030
EBITDAX From Continuing Operations		$	13,241			$	15,238			$	45,272			$	78,787
Income (loss) from Discontinued Operations		$	8,203			$	(481	)		$	20,922			$	(8,251	)
Net Income Attributable to Noncontrolling Interests		--				--				--				(2,245		)
Income (Loss) From Discontinued Operations Attributable to Rex Energy		8,203				(481		)		20,922				(10,496		)
Add Back Depletion, Depreciation, Amortization and Accretion		1				3,481				5,101				18,978
Add Back (Less) Non-Cash Compensation Expense (Income)		(52		)		238				(159		)		659
Add Back Interest Expense		--				3				4				510
Add Back Impairment Expense		--				7,734				3,543				62,531
Add Back Exploration Expense (Income)		--				(74		)		143				394
Add (Less) Back (Gain) Loss on Disposal of Asset2		5				(760		)		(30,530		)		(57,748		)
Add Back (Less) Non-Cash Portion of Noncontrolling Interests		--				1				--				(208		)
Less Income Tax Benefit		(7,852		)		(8,688		)		--				(6,030		)
Add EBITDAX From Discontinued Operations		$	305			$	1,454			$	(976	)		$	8,590
EBITDAX (Non-GAAP)		$	13,546			$	16,692			$	44,296			$	87,377
1 For the year ended December 31, 2016, non-recurring income includes approximately $24.6 million related to the extinguishment of debt, partially offset by approximately $9.1 million in debt exchange expenses, approximately $0.5 million in fees incurred related to the BSP transaction and approximately $8.3 million in expense related to a firm transportation agreement. For the three months ended December 31, 2016, non-recurring income includes amounts related to additional gains related to the extinguishment of debt. For the year ended December 31, 2015, non-recurring costs include net fees incurred to terminate two drilling rig contracts earlier than their original term
2 Includes gain on sale of Water Solutions Holdings of approximately $57.8 million for the year ended December 31, 2015

Adjusted Net Income

"Adjusted Net Income" means, for any period, the sum of net income (loss) from continuing operations before income taxes 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):

	Three Months Ended									Twelve Months Ended
	December 31, (Unaudited)									December 31,  (Unaudited)
		2016				2015					2016				2015
Loss From Continuing Operations Before Income Taxes, as reported	$	(67,376	)		$	(97,556	)			$	(195,201	)		$	(346,752	)
Gain (Loss) on Derivatives, Net		24,261				(14,689	)				32,515				(60,176	)
Cash Settlement of Derivatives		86				15,691					32,571				55,793
Add Back (Less) Losses (Gains) from Financial Derivatives		24,347				1,002					65,086				(4,383	)
Add Back Non-Recurring Costs1		(372	)			--					(6,760	)			4,774
Add Back Impairment Expense		29,275				73,364					74,619				283,244
Add Back Dry Hole Expense		32				--					880				191
Add Back (Less) Non-Cash Compensation Expense (Income)		1,072				1,378					3,078				5,791
Add Back (Less) (Gain) Loss on Disposal of Assets		164				(4	)				(4,121	)			(537	)
Loss From Continuing Operations Before Income Taxes, adjusted	$	(12,858	)		$	(21,816	)			$	(62,419	)		$	(57,672	)
Less Income Tax Benefit, adjusted2		5,143				8,726					24,968				23,069
Adjusted Net Loss From Continuing Operations	$	(7,715	)		$	(13,090	)			$	(37,451	)		$	(34,603	)
Basic - Adjusted Net Loss Per Share	$	(0.08	)		$	(0.24	)			$	(0.47	)		$	(0.64	)
Basic - Weighted Average Shares of Common Stock Outstanding		97,398				54,342					79,256				54,392
1  For the year ended December 31, 2016, non-recurring income includes approximately $24.6 million related to the extinguishment of debt, partially offset by approximately $9.1 million in debt exchange expenses, approximately $0.5 million in fees incurred related to the BSP transaction and approximately $8.3 million in expense related to a firm transportation agreement. For the three months ended December 31, 2016, non-recurring income includes amounts related to additional gains related to the extinguishment of debt. For the year ended December 31, 2015, non-recurring costs include net fees incurred to terminate two drilling rig contracts earlier than their original term
2Assumes an effective 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, (Unaudited)						Twelve Months Ended December 31, (Unaudited)
	2016			2015			2016			2015
GAAP G&A	$	5,384		$	6,441		$	20,621		$	26,694
Non-Cash Compensation Expense	1,072			1,378			3,078			5,791
Cash G&A	$	4,312		$	5,063		$	17,543		$	20,903

 

For more information contact:



Investor Relations

(814) 278-7130

InvestorRelations@rexenergycorp.com

Source: Rex Energy Corporation

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