Exhibit 99.1

Rex Energy Reports Third Quarter Results

 

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Average daily production from oil and NGLs reached a record level of 3.0 MBoe/d

 

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Entered into Anchor/Shipper ethane transportation agreement with Enterprise Products Partners, L.P.

 

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Secured 20,000 acre goal in Warrior Prospect

 

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Completed drilling of three Warrior South wells

 

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First Ohio Utica Shale well averaged a 30-day sales rate of 731 Boe/d (70% Liquids) assuming full ethane recovery

 

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Increased liquids yield from latest “Super Frac” wells

 

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Average daily production increased 63% year-over-year and 14% sequentially

STATE COLLEGE, PA. November 6, 2012 (GLOBE NEWSWIRE) – Rex Energy Corporation (NASDAQ: REXX) today announced its third quarter 2012 operational and financial results as well as fourth quarter guidance.

Third Quarter Operational and Financial Results

Operating revenues from continuing operations for the three and nine months ended September 30, 2012 were $38.9 million and $103.0 million, respectively, which represents an increase of 27% and 24%, respectively, over the same periods in 2011. Commodity revenues, including cash-settled derivatives, were $39.0 million and $107.2 million for the three and nine months ended September 30, 2012, an increase of 22% and 26% respectively, over the comparable periods of 2011. Commodity revenues from oil and natural gas liquids (NGLs) represented 58% and 62% of total commodity revenues for the three and nine months ended September 30, 2012, respectively.

Lease operating expense (LOE) from continuing operations was $11.2 million, or $1.72 per Mcfe for the quarter, a 23% decrease on a per unit basis compared to the same period in 2011. For the nine months ended September 30, 2012, LOE was approximately $34.5 million, or $1.79 per Mcfe, which represents a 28% decrease on a per unit basis when compared to the same period in 2011. The per unit LOE for the nine months ended September 30, 2012 excludes $2.8 million for the retroactive portion of the Pennsylvania impact fee, which equates to approximately $0.15 per Mcfe.

Cash general and administrative (G&A) expenses from continuing operations were $5.6 million for the three months ended September 30, 2012, which represents an 18% decrease on a per unit basis as compared to the same period in 2011. For the nine months ended September 30, 2012, cash G&A expenses from continuing operations were $15.9 million, a 50% decrease on a per unit basis as compared to the same period in 2011.

Loss from continuing operations for the three months ended September 30, 2012 was $1.7 million, or $0.04 per fully diluted share. Income from continuing operations for the nine months ended September 30, 2012 was $58.3 million, or $1.11 per fully diluted share. Adjusted net income for the three months ended September 30, 2012 was $4.0 million, or $0.08 per fully diluted share. Adjusted net income for the nine months ended September 30, 2012 was $11.2 million, or $0.22 per fully diluted share. Loss from discontinued operations for the three months ended September 30, 2012 was $0.3 million, or less than

 

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$0.01 per fully diluted share, and $8.7 million, or $0.17 per fully diluted share, for the nine months ended September 30, 2012. A reconciliation of adjusted net income to GAAP net income, as well as a discussion of the uses of the measure, is presented is the financial highlights attached to this release.

EBITDAX from continuing operations, a non-GAAP measure, was $22.8 million for the third quarter and $62.4 million for the first nine months of 2012. This was an increase of 19% over the third quarter of 2011 and an increase of 39% over the first nine months of 2011. A reconciliation of EBITDAX to GAAP net income, as well as a discussion of the uses of the measure, is presented in the financial highlights attached to this release.

Production Update

Third quarter 2012 net production volumes were 71.1 MMcfe/d, consisting of 52.9 MMcfe/d of natural gas and 3.0 MBoe/d of oil and NGLs, an increase of 63% over the third quarter of 2011 and 14% over the second quarter of 2012. Oil and NGLs accounted for 26% of total net production during the third quarter of 2012. As previously reported, production for the quarter was constrained by an estimated 2.4 MMcfe/d due to processing constraints at the Bluestone cryogenic gas processing complex in Butler County, Pennsylvania.

Including the effects of cash-settled derivatives, realized prices for the three months ended September 30, 2012 were $89.00 per barrel for oil and condensate, $3.83 for natural gas and $42.55 per barrel for NGLs, which was approximately 46% of the average quoted NYMEX oil price for the third quarter. The realized price for NGLs before the effects of hedging was $40.95 per barrel, which is approximately 44% of the average quoted NYMEX oil price for the third quarter.

Third Quarter Capital Investments

During the third quarter of 2012, the company made capital investments of approximately $66.4 million, of which $42.0 million was used to fund Marcellus and Utica operations, $10.0 million was spent on leasing in the Marcellus and Utica shale operating areas, $13.5 million was used to fund conventional drilling, water flood enhancement and ASP projects in the Illinois Basin, and $0.9 million was capitalized interest and corporate expenditures. The Marcellus and Utica capital investment funded the drilling of nine gross (6.4 net) wells, fracture stimulation of nine gross (5.7 net) wells, placing six gross (4.5 net) wells into service and other projects related to drilling and completing wells in the Marcellus region. A more detailed land and leasing update is given below.

Operational Update

Note: Unless specifically stated otherwise in this operational update, all numbers are gross.

 

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Appalachian Basin – Butler Operated Area, Pennsylvania

In the Butler Operated Area, the company has drilled 16 gross (11.2 net) wells year-to-date, with 18 gross (12.2 net) wells fracture stimulated and 17 gross (11.6 net) wells placed into sales. The company currently has 15 gross (10.5 net) wells drilled and awaiting completion.

During the third quarter of 2012, the company completed the two-well Plesniak pad using the “Super Frac” design. The first of the two Plesniak wells was placed into service in October 2012 and produced at a peak 5-day average sales rate of 4.5 MMcfe/d (assuming full ethane recovery) and a peak 25-day average sales rate of 4.3 MMcfe/d assuming full ethane recovery). The Plesniak 3H was also tested under a restricted choke rate.

The second Plesniak well is currently shut-in while the company tests the effects of increased shut-in periods on production. Initial gas analysis from the Plesniak wells indicate that the gas is approximately 1,300 BTU and contains approximately 59% higher liquids (excluding ethane) compared to average the company’s Butler Operated Marcellus production. Assuming full ethane recovery, the Plesniak wells have a liquids content in excess of 50%.

 

Plesniak #3H1
		Natural Gas (mcf/d)		Condensate (bbls/d)		NGLs (bbls/d)		Total (mcfe/d)		% Liquids		Total (Ethane Rejection)
5-day rate		2,048		6		406		4,521		55%		3,171
25-day rate		1,931		6		383		4,263		55%		2,991

 

1	Assumes full ethane recovery, unless otherwise noted.

In addition, the company completed the two-well Pallack pad using its “Super Frac” design. The two wells were placed into service in the third quarter of 2012 and produced at a peak 5-day average sales rate of 4.4 MMcfe (assuming full ethane recovery) per well, and a peak 30-day average sales rate of 3.8 MMcfe (assuming full ethane recovery) per well. As the company previously announced, the Pallacks were tested under restricted choke rates.

Initial gas analysis from the Pallack wells indicates that the gas is approximately 1,300 BTU and contains approximately 56% higher liquids (excluding ethane) as compared to the company’s average Butler Operated Area Marcellus production to date. Assuming full ethane recovery, the Pallack wells have liquids content in excess of 50%.

 

Pallack Wells (Average)1
		Natural Gas (mcf/d)		Condensate (bbls/d)		NGLs (bbls/d)		Total (mcfe/d)		% Liquids		Total (Ethane Rejection)
5-day rate		2,016		4		391		4,385		54%		3,070
30-day rate		1,740		3		337		3,782		54%		2,647

 

1	Assumes full ethane recovery, unless otherwise noted.

 

 

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The company plans to drill its third Upper Devonian test well of 2012 in the fourth quarter and plans to complete three Upper Devonian test wells in 2013. Of the three planned test wells in 2013, one is an Upper Devonian Super Rich test well. This well, the Burgh 1HB, lies above the company’s established 1,300 BTU line.

The company drilled two Super Rich Marcellus test wells during third quarter of 2012, the Wack #9H well and the Grubbs #1H well, and intends to complete these wells in 2013. The Grubbs #1H well will further delineate the company’s increased liquids potential in the northwest portion of its Butler Operated Area.

Lastly, the company has fracture stimulated one of its legacy vertical wells to test the gas quality and liquids potential of the Rhinestreet formation. The well is currently flowing back, and the company continues to evaluate the potential of the formation. The company plans to provide updated information in the fourth quarter of 2012.

 

Total Operated Area – Butler County, PA
		Wells Drilled				Wells Fracture Stimulated				Wells Placed Into Service				Wells Awaiting Completion
YTD			16				18				17				15
FY 2012 Forecast			20				20				21				18

Rex Energy is also pleased to announce that it has entered into a 15-year transportation agreement with an affiliate of Enterprise Product Partners, L.P., (NYSE: EPD) to become an anchor shipper of ethane on the Appalachian-to-Texas Express pipeline (ATEX). The ATEX pipeline will connect MarkWest’s Houston fractionation facility in Washington County, Pennsylvania to the Enterprise Mont Belvieu NGL storage facility in Chambers County, Texas. Volumes to be transported under the agreement begin at 3,000 barrels per day of ethane in 2014 and increase over time to 11,000 barrels per day in 2017 through the end of the contract term.

During the third quarter, the company’s average inlet volume into the Sarsen and Bluestone cryogenic facilities was approximately 58.2 MMcf/d, which was lower than originally expected primarily due to the commissioning of the Bluestone plant. As the company previously reported, the work required to rectify these issues caused approximately 2.4 MMcf/d of processing constraints during the months of July, August and 23 days in September. Both plants are being optimized and refined to maximize NGL recoveries, capacities and reliability.

Appalachian Basin – Warrior North Prospect, Carroll County, Ohio

Rex Energy placed into sales its first Ohio Utica well, the Brace #1H, located in Carroll County, Ohio, at a 24-hour sales rate (assuming full ethane recovery) of 1,094 Boe/d (43% NGLs, 31% gas, 26% condensate). The well went on to average a 5-day sales rate (assuming full ethane recovery) of 1,008 Boe/d and a 30-day sales rate (assuming full ethane recovery) of 731 Boe/d. The Brace #1H was drilled with a lateral length of 4,170 feet, and the completion consisted of a 17-stage fracture stimulation, performing a dual test of a conventional frac and a “Super Frac” on the well. The first 10 stages were a conventional 300’ spaced stimulation while the last 7 stages were performed on a 150’ spacing. Micro-seismic monitoring of the fracture stimulation was performed and the company observed that the “Super Frac” exhibited strong results. Rex Energy plans to utilize the “Super Frac” completion technology on all future Utica completions.

 

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Brace #1H Results (Boe/d)1
		Natural Gas				Condensate				NGLs				Total				Percentage of Liquids				Total (Ethane Rejection  Mode)
24-hour sales rate			336				291				467				1,094				69	%			911
5-day sales rate			306				273				429				1,008				70	%			839
30-day sales rate			221				202				308				731				70	%			610

 

1	Assumes full ethane recovery, unless otherwise noted

Appalachian Basin—Warrior South Prospect, Guernsey, Noble & Belmont Counties, Ohio

The company has completed the drilling of its three planned wells in the Warrior South Prospect with an average lateral length of 3,324. The company currently plans to begin fracture stimulating the Guernsey/Noble pad during the month of November.

 

Total Operated Area – Ohio Utica Shale
		Wells Drilled				Wells Fracture Stimulated				Wells Placed Into Service				Wells Awaiting Completion
YTD			2				1				1				1
FY 2012 Forecast			4				2				1				2

Appalachian Basin – Westmoreland, Clearfield and Centre Counties, Pennsylvania

In the company’s non-operated Westmoreland, Clearfield and Centre counties, Pennsylvania, where WPX Energy serves as the operator, the combined average production for a recent 5 day period was 62.2 MMcf/d. For the month of September, the average production rate in the combined non-operated regions was approximately 62.1 MMcfe/d.

 

Total Non-Operated Area – Westmoreland, Clearfield, and Centre Counties, PA
		Wells Drilled				Wells Fracture Stimulated				Wells Placed Into Service				Wells Awaiting Completion
YTD			5				2				2				7
FY 2012 Forecast			5				2				2				7

Illinois Basin – ASP Project Update

In the Delta Unit, the drilling of pattern wells is complete, and the company continues to perform core flood work and reservoir simulation modeling and expects to be able to book proved reserves for the project as early as year-end 2012. Full ASP injection in the Delta Unit is still scheduled to begin in the second quarter of 2013 with initial production response anticipated for 2014. In the Perkins-Smith project, the company commenced ASP flooding in the second quarter of 2012 and expects to see an initial response in the second quarter of 2013 and peak response in the fourth quarter of 2013. The pilot continues to support the 2011 year-end proved reserves booking of 13% of pore volume recoveries.

 

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Illinois Basin – Conventional

As part of its focus on growing liquids production, the company is continuing its previously announced conventional drilling and re-completion program in Gibson and Posey counties, Indiana. During the quarter, the company drilled 7 wells and performed re-completion operations of an additional 7 wells. The company continues to expect the results from this program to exceed its previously announced estimate of 400 gross BOPD in incremental oil production by the end of 2012. A more detailed update on the company’s conventional drilling and re-completion program in the Illinois Basin will be provided during the fourth quarter 2012 earnings conference call.

Land Update

The company has closed on 800 net acres within the Warrior South Prospect (Guernsey, Noble & Belmont Counties, Ohio) in its Joint Development Area with MFC Drilling, Inc. and ABARTA Oil & Gas Co., Inc. bringing its position to approximately 4,000 net acres. Including agreements currently in place along with the acreage added during the third quarter of 2012, Rex Energy has achieved its goal of securing 20,000 acres in the Warrior Prospects which is prospective for the Utica Shale in what the company believes to be the “wet” corridor of Ohio.

Niobrara Asset Divestiture

In October 2012, the company closed on the sale of a portion of its Niobrara acreage located in Colorado and Nebraska for $3.5 million. The company continues to evaluate the potential divestiture and other strategic opportunities for its approximately 27,000 net acres located in Wyoming. As previously announced, the company does not expect to allocate any capital to this region for the remainder of 2012.

Fourth Quarter and Full Year 2012 Guidance

Rex Energy is providing guidance for the fourth quarter and maintaining guidance for full year 2012 ($ in millions):

 

		4Q2012		Full Year 2012
Production		70 –74 MMcfe/d		66 –69 MMcfe/d
Lease Operating Expense		$11.5 - $13.0		$46 - $50
Cash G&A		$5.3 - $6.3		$20 - $24
Capital Expenditures*		—		$180

 

*	Land acquisition expense is not included in the capital expenditures budget

Conference Call Information

Management will host a live conference call and webcast on Wednesday, November 7, 2012 at 10:00 a.m. ET to review third quarter 2012 financial results and operational highlights. All financial results included in this release and discussed on the third quarter conference call will remain subject to our independent auditor’s review. The telephone number to access the conference call is (877) 849-6312. 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. The replay of the event and reference materials will be available on the company’s website through December 9, 2012.

 

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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 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.

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Forward-Looking Statements

Except for historical information, statements made in this release, including those relating to the timing and nature of Marcellus and Utica Shale development plans, drilling and completion schedules, anticipated fracture stimulation activities, leasing plans, the ASP pilot and expansion plans in the Illinois Basin, and the company’s financial guidance and projections for fourth quarter and full year 2012 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 typically contain words such as “expected”, “expects”, “scheduled”, “planned”, “plans”, “anticipates” and 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):

 

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economic conditions in the United States and globally;

 

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domestic and global demand for oil and natural gas;

 

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volatility in oil, gas, and natural gas pricing;

 

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

 

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

 

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

 

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

 

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drilling and operating risk;

 

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

 

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

 

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

 

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

 

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the availability of equipment, such as drilling rigs and infrastructure, such as transportation pipelines;

 

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

 

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

 

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changes in the company’s drilling plans and related budgets;

 

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the success of prospect development and property acquisition;

 

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

 

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

 

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the adequacy and availability of capital resources, credit, and liquidity including (without limitation) access to additional borrowing capacity; and

 

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

 

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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.

The company’s internal estimates of reserves may be subject to revision and may be different from estimates by the company’s external reservoir engineers at year end. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable,we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.

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For more information, please visit our website or contact:

www.rexenergy.com

Tom Stabley

Chief Executive Officer

(814) 278-7215

tstabley@rexenergycorp.com

Mark Aydin

Manager, Investor Relations

(814) 278-7249

maydin@rexenergy.com

 

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REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

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

 

		September 30, 2012 (unaudited)				December 31, 2011
ASSETS
Current Assets
Cash and Cash Equivalents		$	3,783			$	11,796
Accounts Receivable			25,898				17,717
Short-Term Derivative Instruments			9,275				10,404
Assets Held for Sale			10,439				24,808
Inventory, Prepaid Expenses and Other			1,273				1,191
Total Current Assets			50,668				65,916
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties			463,310				349,938
Unevaluated Oil and Gas Properties			159,763				123,241
Other Property and Equipment			49,140				43,542
Wells and Facilities in Progress			85,707				66,548
Pipelines			6,706				4,408
Total Property and Equipment			764,626				587,677
Less: Accumulated Depreciation, Depletion and Amortization			(137,794	)			(107,433	)
Net Property and Equipment			626,832				480,244
Deferred Financing Costs and Other Assets – Net			2,622				3,405
Equity Method Investments			17,161				41,683
Long-Term Deferred Tax Asset			0				1,727
Long-Term Derivative Instruments			2,253				8,576
Total Assets		$	699,536			$	601,551
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable		$	34,541			$	41,558
Accrued Expenses			24,693				15,682
Short-Term Derivative Instruments			1,900				2,363
Current Deferred Tax Liability			2,049				2,141
Liabilities Related to Assets Held for Sale			539				1,622
Total Current Liabilities			63,722				63,366
Senior Secured Line of Credit and Long-Term Debt			172,751				225,138
Long-Term Derivative Instruments			2,454				1,275
Long-Term Deferred Tax Liability			17,865				84
Other Deposits and Liabilities			3,818				744
Asset Retirement Obligation			24,085				18,670
Total Liabilities		$	284,695			$	309,277
Commitments and Contingencies
Stockholders’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 52,853,214 shares issued and outstanding on September 30, 2012 and 44,859,220 shares issued and outstanding on December 31, 2011			52				44
Additional Paid-In Capital			450,099				376,843
Accumulated Deficit			(35,972	)			(84,888	)
Rex Energy Stockholders’ Equity			414,179				291,999
Noncontrolling Interests			662				275
Total Stockholders’ Equity			414,841				292,274
Total Liabilities and Stockholders’ Equity		$	699,536			$	601,551

 

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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,
		2012				2011				2012				2011
OPERATING REVENUE
Oil, Natural Gas and NGL Sales		$	34,711			$	30,259			$	93,893			$	81,087
Field Services Revenue			4,170				442				8,990				1,679
Other Revenue			48				54				137				158
TOTAL OPERATING REVENUE			38,929				30,755				103,020				82,924
OPERATING EXPENSES
Production and Lease Operating Expense			11,234				8,990				34,505				24,055
General and Administrative Expense			6,858				4,461				18,043				18,603
Loss on Disposal of Assets			16				6				110				464
Impairment Expense			292				2,379				3,357				2,928
Exploration Expense			1,206				303				3,511				2,203
Depreciation, Depletion, Amortization and Accretion			12,396				7,762				33,082				19,641
Field Services Operating Expense			2,985				618				5,706				1,637
Other Operating Expense (Income)			399				(23	)			693				(85	)
TOTAL OPERATING EXPENSES			35,386				24,496				99,007				69,446
INCOME FROM OPERATIONS			3,543				6,259				4,013				13,478
OTHER INCOME (EXPENSE)
Interest Expense			(852	)			(474	)			(3,655	)			(1,024	)
Gain (Loss) on Derivatives, Net			(5,893	)			12,174				5,188				12,787
Other Income (Expense)			(497	)			41				92,241				61
Income (Loss) on Equity Method Investments			(174	)			105				(3,738	)			(165	)
TOTAL OTHER INCOME (EXPENSE)			(7,416	)			11,846				90,036				11,659
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX			(3,873	)			18,106				94,049				25,137
Income Tax (Expense) Benefit			2,131				(5,440	)			(35,768	)			(8,207	)
INCOME (LOSS) FROM CONTINUING OPERATIONS			(1,742	)			12,666				58,281				16,930
Loss From Discontinued Operations, Net of Income Taxes			(258	)			(20,812	)			(8,662	)			(29,195	)
NET INCOME (LOSS)			(2,000	)			(8,146	)			49,619				(12,265	)
Net Income (Loss) Attributable to Noncontrolling Interests			193				44				516				(14	)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY		$	(2,193	)		$	(8,190	)		$	49,103			$	(12,251	)
Earnings per common share:
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders		$	(0.04	)		$	0.29			$	1.13			$	0.39
Basic – Net Loss From Discontinued Operations Attributable to Rex Common Shareholders			0.00				(0.47	)			(0.17	)			(0.67	)
Basic – Net Income (Loss) Attributable to Rex Common Shareholders		$	(0.04	)		$	(0.18	)		$	0.96			$	(0.28	)
Basic – Weighted Average Shares of Common Stock Outstanding			52,036				43,951				51,120				43,897
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders		$	(0.04	)		$	0.28			$	1.11			$	0.38
Diluted – Net Loss From Discontinued Operations Attributable to Rex Common Shareholders			0.00				(0.47	)			(0.17	)			(0.66	)
Diluted – Net Income (Loss) Attributable to Rex Common Shareholders		$	(0.04	)		$	(0.19	)		$	0.94			$	(0.28	)
Diluted – Weighted Average Shares of Common Stock Outstanding			52,805				44,384				52,018				44,448

 

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REX ENERGY CORPORATION

CONSOLIDATED OPERATIONAL HIGHLIGHTS

UNAUDITED

 

		Three Months Ending September 30,								Nine Months Ending September 30,
		2012				2011				2012				2011
Oil, Natural Gas and NGL Sales (in thousands):
Oil Sales		$	16,263			$	15,500			$	48,587			$	47,549
Natural Gas Sales			14,492				11,485				35,917				26,218
NGL Sales			3,956				3,274				9,389				7,320
Cash Settled Derivatives:
Oil			—				(5	)			(286	)			(648	)
Natural Gas			4,119				1,607				13,394				4,463
NGL			155				—				248				—
Total oil, natural gas and NGL sales including cash settled derivatives		$	38,985			$	31,861			$	107,249			$	84,902
Production:
Oil (Bbls)			182,759				179,915				524,149				517,923
Natural Gas (Mcf)			4,865,953				2,583,768				13,191,301				5,768,163
NGL (Bbls)			96,610				59,869				236,570				136,876
Total Production (Mcfe)a			6,542,167				4,022,472				17,755,615				9,696,957
Average Daily Production
Oil (Bbls)			1,987				1,956				1,913				1,897
Natural Gas (Mcf)			52,891				28,084				48,143				21,129
NGL (Bbls)			1,050				651				863				501
Total Production (Mcfe)a			71,111				43,723				64,802				35,520
Average Price per Unit:
Realized oil sales price per Bbl		$	89.00			$	86.15			$	92.70			$	91.81
Realized impact of cash settled derivatives per Bbl			—				(0.03	)			(0.55	)			(1.25	)
Net realized price per Bbl		$	89.00			$	86.12			$	92.15			$	90.56
Realized natural gas sales price per Mcf		$	2.98			$	4.45			$	2.72			$	4.55
Realized impact of cash settled derivatives per Mcf			0.85				0.62				1.02				0.77
Net realized price per Mcf		$	3.83			$	5.07			$	3.74			$	5.32
Realized NGL sales price per Bbl		$	40.95			$	54.69			$	39.69			$	53.48
Realized impact of cash settled derivatives per Bbl			1.60				—				1.05				—
Net realized price per Bbl		$	42.55			$	54.69			$	40.74			$	53.48
LOE/Mcfeb		$	1.72			$	2.23			$	1.79			$	2.48

 

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

b	For the nine months ended September 30, 2012, excludes the impact of the retroactive portion of the Pennsylvania Impact Fee, which equates to approximately $0.15 per Mcfe.

 

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REX ENERGY CORPORATION

COMMODITY DERIVATIVES – CURRENT HEDGING POSITIONS

 

		2012				2013				2014
Oil Derivatives (Bbl)
Collar Contracts
Volume			150,000 Bbls				540,000 Bbls				—
Ceiling		$	111.08			$	112.56			$	—
Floor		$	68.39			$	72.44			$	—
Collar Contracts with Short Puts
Volume			—				—				192,000 Bbls
Ceiling		$	—			$	—			$	106.25
Floor		$	—			$	—			$	80.00
Short Put		$	—			$	—			$	65.00
Natural Gas Derivatives (Mcf)
Swap Contracts
Volume			1,440,000 Mcf				5,970,000 Mcf				1,200,000 Mcf
Price		$	4.06			$	3.82			$	3.42
Swaption Contracts
Volume			150,000 Mcf				600,000 Mcf				—
Price		$	5.25			$	4.50			$	—
Collar Contracts
Volume			750,000 Mcf				3,360,000 Mcf				1,800,000 Mcf
Ceiling		$	5.89			$	5.68			$	4.45
Floor		$	4.70			$	4.77			$	3.52
Put Contracts
Volume			—				2,640,000 Mcf				—
Floor		$	—			$	5.00			$	—
Collar Contracts with Short Puts
Volume			660,000 Mcf				2,520,000 Mcf				1,800,000 Mcf
Ceiling		$	5.13			$	4.88			$	4.75
Floor		$	4.48			$	4.17			$	3.63
Short Put		$	3.66			$	3.35			$	2.75
Call Contracts
Volume			—				—				1,800,000 Mcf
Ceiling		$	—			$	—			$	5.00
Natural Gas Liquids (Bbls)
Swap Contracts
Volume			27,000 Bbls				108,000 Bbls				—
Price		$	43.26			$	43.26			$	—

 

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The following table has been added to provide clarification on the components of Gain on Derivatives, net under Other Income (Expense) on the Consolidated Statements of Operations for each of the periods presented (in thousands):

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2012				2011				2012				2011
Realized Gains (Losses) from Financial Derivatives:
Crude Oil Derivatives		$	0			$	(5	)		$	(287	)		$	(648	)
Natural Gas Liquid Derivatives			155				0				248				0
Natural Gas Derivatives			4,119				1,607				13,394				4,463
Total Realized Gains from Financial Derivatives		$	4,274			$	1,602			$	13,355			$	3,815
Unrealized Gains (Losses) from Financial Derivatives:
Crude Oil Derivatives		$	(1,492	)		$	7,120			$	2,067			$	5,999
Natural Gas Liquid Derivatives			(586	)			0				558				0
Natural Gas Derivatives			(8,089	)			3,452				(10,792	)			2,973
Total Unrealized Gains (Losses) from Financial Derivatives		$	(10,167	)		$	10,572			$	(8,167	)		$	8,972
Gain on Derivatives, net		$	(5,893	)		$	12,174			$	5,188			$	12,787

REX ENERGY COPRORATION

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, the retroactive portion of the Pennsylvania Impact Fee, 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.

 

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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 September 30,								Nine Months Ended September 30,
		2012				2011				2012				2011
Net Income (Loss) From Continuing Operations		$	(1,742	)		$	12,666			$	58,281			$	16,930
Net (Income) Loss Attributable to Noncontrolling Interests			(193	)			(44	)			(516	)			14
Income (Loss) From Continuing Operations Attributable to Rex Energy			(1,935	)			12,622				57,765				16,944
Add Back Retroactive Portion of New Pennsylvania Impact Fee			—				—				2,809				—
Add Back Depletion, Depreciation, Amortization and Accretion			12,396				7,762				33,082				19,641
Add Back Non-Cash Compensation Expense			1,305				295				2,147				1,295
Add Back Interest Expense			852				474				3,655				1,024
Add Back Impairment Expense			292				2,379				3,357				2,928
Add Back Exploration Expenses			1,206				303				3,511				2,203
Add Back (Less) Loss (Gain) on Disposal of Assets			526				6				(92,128	)			464
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives			10,166				(10,572	)			8,167				(8,972	)
Less Non-Cash Portion of Noncontrolling Interests			(36	)			(8	)			(64	)			(139	)
Add Back (Less) Income Tax Expense (Benefit)			(2,131	)			5,440				35,768				8,207
Add Back Non-Cash Portion of Equity Method Investment			174				416				4,294				1,118
EBITDAX From Continuing Operations		$	22,815			$	19,117			$	62,363			$	44,713
Net Loss From Discontinued Operations		$	(258	)		$	(20,813	)		$	(8,662	)		$	(29,197	)
Add Back Depletion, Depreciation, Amortization and Accretion			—				(84	)			—				77
Add Back Non-Cash Compensation Expense			(43	)			19				(31	)			46
Add Back Impairment Expense			—				—				12,951				11,255
Add Back Exploration Expenses			329				30,249				810				31,562
Add Back Loss on Disposal of Assets			4				—				148				—
Less Income Tax Benefit			(203	)			(9,808	)			(6,064	)			(15,073	)
Add EBITDAX From Discontinued Operations		$	(171	)		$	(437	)		$	(848	)		$	(1,330	)
EBITDAX (Non-GAAP)		$	22,644			$	18,680			$	61,515			$	43,383

 

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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 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 has reported 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 income from continuing operations to its adjusted net income for each of the periods presented ($ in thousands):

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
		2012				2011				2012				2011
Income (Loss) From Continuing Operations Before Income Taxes, as reported		$	(3,873	)		$	18,106			$	94,049			$	25,137
Add Back Retroactive Portion of PA Impact Fee			—				—				2,809				—
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives			10,166				(10,571	)			8,167				(8,972	)
Add Back Impairment Expense			292				2,379				3,357				2,928
Add Back Dry Hole Expense			—				—				306				6
Add Back Non-Cash Compensation Expense			1,305				295				2,147				1,295
Add Back (Less) (Gain) Loss on Disposal of Assets a			526				6				(92,128	)			464
Add Back (Less) Loss (Income) Attributable to Noncontrolling Interests			(193	)			(44	)			(516	)			14
Income Before Income Taxes, adjusted			8,223				10,171				18,191				20,872
Less Income Taxes, adjusted b			4,243				3,061				6,949				6,804
Adjusted Net Income		$	3,980			$	7,110			$	11,242			$	14,068
Basic Net Income Comparable to Analyst Estimates per Share		$	0.08			$	0.16			$	0.22			$	0.32
Basic — Weighted average shares of common stock outstanding			52,036				43,951				51,120				43,897

 

a	Includes gain on sale of Keystone Midstream Services, LLC of approximately $92.2 million for the three and nine months ended September 30, 2012.

b	Income tax adjustment represents effective tax rate for the period.

 

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