Rex Energy Corporation Announces 82% Increase in Proved Reserves, 92% Annual Production Growth and Provides Operational Update

• Increased 2011 proved reserves 82% over 2010, average daily production increased 92% over 2010
• Marcellus Shale wells in Butler County, Pennsylvania increase EURs 20% to 5.3 Bcfe
• Marcellus Shale wells in Westmoreland County, Pennsylvania increase EURs 40% to 4.2 Bcfe
• Company announces proved reserves for full scale ASP expansion

STATE COLLEGE, Pa., Jan. 17, 2012 (GLOBE NEWSWIRE) -- Rex Energy Corporation (Nasdaq:REXX) today announced its total proved oil and natural gas reserves as of December 31, 2011, unaudited fourth quarter and full year 2011 production results and provided an update on its operations.

"I am pleased to announce this is our fifth consecutive quarter of double digit production growth, and we closed at the high end of our production guidance," said Thomas Stabley, Chief Executive Officer of Rex Energy. "We exited 2011 in a position of strength, as evidenced by our production growth and increase in proved reserves. We are well positioned to benefit from this momentum as we continue to focus on expanding our operations in the liquids-rich areas of Pennsylvania and Ohio."

Proved Reserves

Rex Energy reported year end 2011 proved oil and gas reserves of 366.2 Bcfe, an increase of 82% over 2010. Of the 366.2 Bcfe of proved reserves, 75% was attributable to natural gas with 25% attributable to oil, natural gas liquids and condensate. The proved developed portion of the 2011 reserves increased to 47% from 42% in 2010. The proved reserve estimates as of December 31, 2011 were prepared by the company's third-party independent reserve engineers, Netherland, Sewell & Associates, Inc. For more information on proved reserves and related definitions, see "Note on Hydrocarbon Volumes and Estimates" below. Rex Energy successfully replaced 1,093% of its estimated 2011 production of 14,258 MMcfe with a proved reserves-to-production ratio of 25.8 years.

The following table summarizes the company's proved reserves and Finding and Development Costs as of December 31 of the years indicated:

Drill-Bit Finding and Development Cost is defined as the sum of total capital deployed, less lease acquisitions, divided by total extensions and discoveries. All-In Finding and Development Cost is defined as the sum of total capital deployed divided by the sum of extensions, discoveries, acquisitions, divestitures, conversions, revisions, less prior year's production. Finding and Development Cost per production unit is a non-GAAP metric used by the industry, investors and analysts to measure the company's ability to establish a long-term trend of adding reserves at a reasonable cost. The calculations presented by the company are based on estimated and unaudited costs incurred excluding estimated abandonment costs.

Full year unaudited capital expenditures for 2011 are estimated to be approximately $301.1 million, up from the company's previously issued guidance of $270.0 million. This includes approximately $23.9 million from discontinued operations in the company's DJ Basin. The increase is primarily due to leasing costs associated with additional acreage in the company's Warrior prospect in the Ohio Utica Shale and additional drilling and completion costs in the Appalachian region. A detailed breakdown of the company's capital expenditures will be provided in the company's year-end release.

Below is a reconciliation of the changes in the company's proved reserves between December 31, 2010 and December 31, 2011 (SEC pricing for 2011 was $92.71/Bbl for oil and NGLs and $4.12/Mcf for natural gas, adjusted for contractual agreements): 

The following table summarizes Rex Energy's total proved reserves by region as of December 31, 2011:

PV-10 represents the present value, discounted at 10% per annum, of estimated future net revenue before income tax and asset retirement obligations of our estimated proved reserves. PV-10 is a non-GAAP financial measure because it excludes the effect of income taxes and asset retirement obligations. Rex believes that PV-10 is a useful measure for evaluating the relative value of our oil and natural gas properties. Rex also believes that investors and securities analysts may use PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. Rex uses PV-10 as one measure of the value of the company's proved reserves and to compare relative values of reserves among exploration and production companies without regard to income taxes or asset retirement obligations. Rex also uses this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10 should not be considered as an alternative to standardized measure of discounted future net cash flows as defined under GAAP. 

The following table shows the reconciliation of standardized measure of discounted future net cash flows to PV-10 as of December 31, 2011: 

Approximately 54% of Rex's proved reserve growth was attributable to expanded horizontal drilling in the Butler County, Pennsylvania operated area. Rex also saw considerable growth in Marcellus Shale production through the work of its joint venture partner, Williams, in Westmoreland, Clearfield and Centre Counties, Pennsylvania. When including the net reserves gained in the Williams operated areas, total Marcellus Shale proved reserves increased by 109% when compared to 2010 proved reserves. In addition, the increase in proved reserves in 2011 was a result of increased drilling and higher Estimated Ultimate Recoveries (EURs) due to improved drilling and completion methods. For a description of EURs, see "Note on Hydrocarbon Volumes and Estimates" below. 

Listed below are the improvements to EURs in all three of our Marcellus areas ($ in millions): 

Below is a summary of the number of wells by proved reserve classification as of December 31 for the years indicated: 

The proved undeveloped to proved developed ratio for the year ending December 31, 2011 is 1.27 to 1.00.

Rex also announced proved reserves attributable to its Alkaline Surfactant Polymer (ASP) projects in the Lawrence Field in Illinois as of December 31, 2011. Proved developed non-producing reserves in the amount of 132 gross MBbls were booked, representing a P-90 recovery factor of 13 percent of pore volume in the Perkins-Smith Unit immediately adjacent to the Middagh pilot area. This recovery factor falls near the mid-point of previously announced recovery projections from 8 to 20 percent pore volume. "Booking proved reserves from the tertiary recovery project in the Bridgeport Sand validates the success of ASP technology," said Pat McKinney, President and Chief Operating Officer of Rex Energy. "The confirmation of proved reserves in this project area provides extra impetus to press forward with our plans to initiate development of the 358 acre Delta Unit project in 2012." Based on the recoveries demonstrated in the Middagh pilot and the proved reserves booking confidence, Rex believes there are 24.9 to 62.2 million gross barrels of potential recoverable oil attributable to ASP tertiary recovery in the Lawrence Field of Illinois. "With current pore volume recovery and continued development of the tertiary ASP projects, we have the potential to double our current Lawrence Field production by 2015," commented McKinney. For a description of "potential recoverable oil," see "Note on Hydrocarbon Volumes and Estimates" below.

Unaudited Fourth Quarter and Full Year 2011 Production

Consolidated net production from continuing operations for the fourth quarter of 2011 averaged an estimated 49.2 MMcfe per day, which is at the high end of the company's previously issued guidance. This represents a 12% increase over the third quarter of 2011 and an increase of 116% over the fourth quarter of 2010. The company's production increase during the three months ended December 31, 2011 represents its fifth consecutive period of double digit sequential quarter-over-quarter production growth. Oil and natural gas liquids accounted for 30% of total net production from continuing operations for the quarter.

The company's December 2011 exit rate from continuing operations averaged an estimated 54.6 MMcfe per day, which is also at the high end of the company's previously issued exit rate guidance. This represents an increase of approximately 119% over the December 2010 exit rate. 

Total production from continuing operations averaged an estimated 39.0 MMcfe per day for the fiscal year ended December 31, 2011, of which 29% was attributable to oil, 63% to natural gas and 8% to natural gas liquids. This represents an increase of 92% year-over-year. Production from natural gas and natural gas liquids grew 189% and 644%, respectively, due to the company's continued expansion and success in its operated Butler County, Pennsylvania region and its non-operated Westmoreland and Clearfield Counties, Pennsylvania regions.  The company's percentage of commodity revenue from oil, natural gas liquids and related cash-settled derivatives for full year 2011 was 62%.

Realized prices for crude oil, after the effects of cash-settled derivatives were $90.32 per barrel for the fourth quarter 2011 and $90.50 per barrel for the full year 2011. Realized prices for natural gas, after the effects of cash-settled derivatives, were $4.57 per Mcf for the fourth quarter 2011 and $5.05 per Mcf for the full year 2011. Realized prices for natural gas liquids were $54.10 per barrel for the fourth quarter 2011 and $53.65 for the full year 2011, which was approximately 58% and 56% of the NYMEX quoted average price of oil for fourth quarter and full year of 2011, respectively. The company's gain on cash settled derivatives for 2011 was $6.2 million, or $0.44 per Mcfe. 

Operational Update

Appalachia Basin - Butler County, Pennsylvania Operated Area

In its Butler County operated area, Rex Energy has drilled 31 gross (19.8 net) wells, fracture stimulated 19 gross (12.5 net) wells and placed 21 gross (13.9 net) wells into service. The company currently has an inventory of 19 gross (12.2 net) wells drilled and awaiting completion. The company has two gross (1.4 net) wells completed and awaiting pipeline infrastructure. 

The company recently fracture stimulated and placed into service three gross (1.3 net) wells on its seven well Grosick pad and has placed into service two gross (1.4 net) wells on its two well McElhinney pad.  The three Grosick wells, prior to being shut in during the completion of the remaining four of seven Grosick wells, flowed at a restricted five day average sales rate of 2.9 MMcfe/d per well.  The two McElhinney wells with average lateral length of approximately 3,000 feet per well had restricted five day average sales rates of approximately 3.1 MMcfe/d per well and 30 day average sales rates of approximately 3.3 MMcfe/d per well.

At the company's jointly-owned Sarsen cryogenic gas processing plant, the gross inlet volume averaged 34.6 MMcf per day for the month of December 2011. The company expects the inlet capacity of the Sarsen plant to increase to 40.0 MMcf/d with the installation of the Voll Compressor station, which remains on schedule to be commissioned in February 2012.

Rex has commenced its 2012 Butler County drilling program with the spudding of the two well Plesniak pad and has begun fracture stimulation operations on the remaining four wells of the seven well Grosick pad. A detailed schedule of the 2012 drilling program within Butler County can be found in the updated corporate presentation available on the company's website www.rexenergy.com.

Appalachia Basin - Warrior Prospect, Carroll County, Ohio

In the company's Warrior Prospect in Carroll County, Ohio, which is located in the liquids-rich portion of the Utica Shale, Rex Energy has met its goal of leasehold and leasehold commitments of approximately 15,000 net acres. At the end of 2011, the company had closed on approximately 13,000 net acres and expects to close on the remaining acreage during the first quarter of 2012 pending clearance of title. The company expects to continue leasing additional acreage as market conditions permit.

As previously announced, the company expects to drill three gross (2.4 net) wells, fracture stimulate three gross (2.4 net) wells, and place into service three gross (2.4 net) wells in its Utica Shale Warrior Prospect in 2012. The company plans to commence drilling operations on its first Warrior Prospect well during the second quarter of 2012 and does not expect to have any wells drilled and awaiting completion in the area at the end of 2012.

Appalachia Basin - Westmoreland, Clearfield, and Centre Counties Non-Operated Area

In the Westmoreland, Clearfield and Centre counties non-operated areas, where Williams serves as the operator, Williams has drilled 26 gross (10.4 net) wells, fracture stimulated 29 gross (11.6 net) wells and placed into service 30 gross (12 net) wells during 2011. Williams has drilled three gross (1.2 net) wells in Westmoreland County which are awaiting completion.

During the fourth quarter of 2011, Williams placed into sales 13 gross (5.2 net) wells in the Westmoreland County non-operated area. Williams has recently placed into service the two well National Metals #1 pad and the five well Marco #1 pad. The seven wells had an average five day sales rate of 5.6 MMcf/d per well, with the National Metals #1 pad having an average 30 day sales rate of 5.5 MMcf/d per well. Williams also recently placed into service two of the three wells on the McBroom #1 pad, the two well Skacel #1 pad and the two well Frye #1 pad. The six wells had an average five day sales rate of 2.5 MMcf/d per well with the wells curtailed during the start-up of the newly commissioned high-pressure sales line.

Williams has recently completed a high-pressure pipeline tap into the Peoples line, which will enable the company to sell production from the eastern side of the Westmoreland field. During the month of December 2011, gross sales for the Westmoreland non-operated area averaged 47.0 MMcf/d. During the last seven days, gross sales in the Westmoreland non-operated area averaged approximately 66.0 MMcf/d, with the high-pressure sales line flowing at an average of approximately 20.5 MMcf/d.

In the Clearfield and Centre County non-operated area, Williams has placed into service the remaining two wells on the four well Resource Recovery pad. The four gross (1.6 net) wells had an average five day sales rate of 5.0 MMcf/d per well and an average 30 day sales rate of 4.1 MMcf/d per well. The wells are flowing into sales through the Columbia gas line with an average of 13.3 MMcf/d during the month of December 2011.

A detailed schedule of the 2012 drilling program for the Westmoreland, Centre and Clearfield County non-operated area can be found in the updated corporate presentation available on the company's website www.rexenergy.com.

Illinois Basin - ASP Project Update

In Rex Energy's ASP project area in the Illinois Basin, the company is moving forward with its expansion into the 58-acre Perkins Smith Proved Non-Producing Reserves project area. ASP injection in this area is expected to begin in the second quarter of 2012. The company anticipates production response from the Perkins-Smith Unit to start in early 2013 with peak production rates of between 175-250 gross barrels of oil per day expected to occur by the fourth quarter of 2013.

Development and testing work is underway to initiate the 358 acre Delta Unit ASP flood. The company continues to evaluate various development and spacing scenarios to determine the optimal pattern performance in this project. In Rex Energy's Middagh ASP Pilot Project Area, the project has maintained a range of 65-75 Bbls/d of gross production, with oil cuts maintaining a range of 8-11 percent.

Midstream Asset Divestiture

Rex Energy and its partners in Keystone Midstream, LLC have engaged Evercore Partners to market their jointly owned midstream assets in Butler County.  The transaction would include the existing Sarsen and Bluestone Cryogenic plants plus related gathering and infrastructure.  The process is currently underway, and is expected to conclude during the second quarter of 2012.  The company believes that its portion of the midstream assets in Butler County and divestiture of its DJ Basin assets will provide the company with approximately $90-$110 million of liquidity during the first half of 2012.

About Rex Energy Corporation

Rex Energy (www.rexenergy.com) is headquartered in State College, Pennsylvania and is an independent oil and gas 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.

The operational updates in this press release are reflected in the company's January 2012 corporate presentation, which is available on the Rex Energy website www.rexenergy.com under the Events & Presentations section of the Investor Relations homepage.

The Rex Energy Corporation logo is available at http://www.globenewswire.com/newsroom/prs/?pkgid=5489

Forward-Looking Statements

Except for historical information, statements made in this release, including those relating to the expected increase in inlet capacity for the Sarsen plant, expected timing of and plans for drilling, completion and fracture stimulation activities for 2012, potential leasing activities in 2012, timing of developments in the ASP projects, and the potential divestiture of the company's jointly owned midstream assets in Butler County, Pennsylvania 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 are indicated by words such as "expected", "expects", "anticipates" and similar words. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and the company's future performance are subject to a wide range of business risks and uncertainties, and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including (without limitation) the following:

• adverse economic conditions in the United States and globally;
• domestic and global demand for oil and natural gas;
• sustained or further declines in the prices the company receives for oil and natural gas;
• the effects of government regulation, permitting and other legal requirements;
• the geologic quality of the company's properties with regard to, among other things, the existence of hydrocarbons in economic quantities;
• uncertainties about the estimates of the company's oil and natural gas reserves;
• the company's ability to increase production and oil and natural gas income through exploration and development;
• the company's ability to successfully apply horizontal drilling techniques and tertiary recovery methods;
• the number of well locations to be drilled, the cost to drill and the time frame within which they will be drilled;
• the effects of adverse weather on operations;
• drilling and operating risks;
• the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services;
• pipeline and capacity restraints in the midstream, or other external limitations on the company's ability to place its production into sales;
• the availability of equipment, such as drilling rigs and transportation pipelines;
• changes in the company's drilling plans and related budgets;
• the adequacy of capital resources and liquidity including (without limitation) access to additional borrowing capacity;
• the difficult conditions in the domestic and global capital and credit markets; and
• uncertainties associated with our legal proceedings and the 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.

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 the company believes the expectations and forecasts reflected in forward-looking statements are reasonable, it 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.

Note on Hydrocarbon Volumes and Estimates

The SEC permits publicly-reporting oil and gas companies to disclose "proved reserves" in their filings with the SEC. "Proved reserves" are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. SEC rules also permit the disclosure of "probable" and "possible" reserves. Rex Energy discloses proved reserves but does not disclose probable or possible reserves. We do use certain broader terms such as "potential recoverable oil," "EUR" (estimated ultimate recovery of resources, defined below) and other descriptions of volumes of potentially recoverable hydrocarbon resources throughout this release. These broader classifications do not constitute "reserves" as defined by the SEC and we do not attempt to distinguish these classifications from probable or possible reserves as defined by SEC guidelines.

The company defines EUR as the cumulative oil and gas production expected to be economically recovered from a reservoir or individual well from initial production until the end of its useful life. Our estimates of EURs and recoverable resources have been prepared internally by our engineers and management without review by independent engineers. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. We include these estimates to demonstrate what we believe to be the potential for future drilling by the company. Ultimate recoveries will be dependent upon numerous factors including actual encountered geological conditions, the impact of future oil and gas pricing and exploration costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases. 

For more information, please visit our website or contact:

www.rexenergy.com