• Proved developed reserves increased to 586.7 Bcfe, or 65%, over 2013
  • Drill-bit F&D in Butler Operated Area of $0.41/mcfe, among the best in the Marcellus Shale
  • Overall drill-bit F&D of $0.67 / mcfe
  • Successfully replaced ~972% of production in 2014
  • SEC PV-10 of $1.2 billion, an increase of 80% over 2013 SEC PV-10
  • Successful confirmation of downspacing to 650 feet from 750 feet in Butler Operated Area

STATE COLLEGE, Pa., Jan. 27, 2015 (GLOBE NEWSWIRE) — Rex Energy Corporation (“Rex Energy”) (Nasdaq:REXX) today announced its total estimated proved oil, NGL and natural gas reserves as of December 31, 2014.

Estimated Proved Reserves

Rex Energy reported proved oil and natural gas reserves as of December 31, 2014 of 1,337 Bcfe, an increase of approximately 487.0 Bcfe, or 57% from total proved reserves reported at year-end 2013. Proved developed reserves were 586.7 Bcfe at year-end 2014, as compared to 356.5 Bcfe at year-end 2013, a 65% increase. In addition, the company’s PV-10 (a non-GAAP measure of estimated future cash flows, excluding income taxes, discounted at 10%) increased approximately $536.6 million, or 80% to $1.2 billion, from year-end 2013 PV-10 of $668.7 million. Of the approximately 1.3 Tcfe of total proved reserves, 37% was attributable to oil, condensate and natural gas liquids, with 63% attributable to natural gas. The proved reserves estimates as of December 31, 2014 were prepared by the company’s independent reservoir engineers, Netherland, Sewell & Associates, Inc. (NSAI). Rex Energysuccessfully replaced 972% of its estimated production of 56,352 MMcfe for the twelve months ended December 31, 2014 with a proved reserves-to-production ratio of 23.7 years. For more information on proved reserves and related information, see “Note on Hydrocarbon Volumes and Estimates” below.

The company and its third party engineers, NSAI, were successful in confirming down-spacing from 750 to 650 foot spaced laterals in the Butler Operated Area. In addition, NSAI has confirmed, based upon the data currently available, the Marcellus and Upper Devonian Burkett are separate reservoirs and can be booked independently within the company’s acreage. The production performance history of the Upper Devonian Burkett wells is at a level that allows PUD type-curves to be booked at the same level as the Marcellus shale wells. The company expects to update its Butler Operated Area Marcellus and Ohio Utica Warrior North and South type curves in the coming weeks.

The following table summarizes the company’s changes in proved reserves between the period of December 31, 2013 and December 31, 2014 in Bcfe.

Balance – December 31, 2013 849.8
Additions (Extensions) 462.0
Additions (Extensions) in Butler Op. Area due to 650 ft. Downspacing 61.8
Acquisitions and Divestitures 24.1
PUD Improved Recovery 21.3
PUD Removal – 5-year rule (58.5)
PDP Field Performance/Revisions 32.7
Production (56.4)
Balance – December 31, 2014 1,336.8

The following table summarizes the company’s proved reserves and Finding and Development Costs as of December 31, 2014, 2013 and 2012.

Three Year
12/31/2012 12/31/2013 12/31/2014 Average
Proved Reserves (MMcfe)1 618,050 849,785 1,336,809
Production (Mcfe) 24,557 33,850 56,352
Drill-Bit Capital Deployed (millions)2, 3 $176.9 $283.3 $351.6
Drill-Bit Finding and Development Cost ($/Mcfe) 2 $0.90 $0.91 $0.67 $0.79
Butler Drill-Bit Finding and Development Cost ($/Mcfe)2 $0.50 $0.46 $0.41 $0.44
All-In Capital Deployed (millions)2, 4 $238.9 $337.65 $549.85
All-In Finding and Development Cost ($/Mcfe) 2 $0.95 $1.46 $1.13 $1.16
__________________
1 Values obtained from certified reports from Netherland, Sewell & Associates, Inc. as of December 31, 2012, 2013, and 2014, respectively
2 A non-GAAP measure. A further discussion of Finding and Development Cost and components thereof is included in the appendix attached to this release
3 Exploration and development capital employed
4 Includes all exploration and development capital, leasing and other corporate capital spending
5 Excludes capital expenditures related to Keystone Clearwater Solutions

Below is a reconciliation of the changes in the company’s proved reserves between December 31, 2013 and December 31, 2014 (SEC pricing for the twelve months ended December 31, 2014 was the West Texas Intermediate posted price of $91.48/Bbl for oil and NGLs and Henry Hub spot price of$4.35/MMbtu for natural gas, adjusted for contractual agreements).

Natural Gas Oil C3+ NGLs Ethane Total
(MMcf) (Mbbl) (Mbbl) (Mbbl) (MMcfe)
Balance – December 31, 2013 521,283 8,620 22,268 23,862 849,785
Extensions and discoveries 326,464 1,723 15,601 15,560 523,765
Production1 (37,011) (1,141) (1,531) (551) (56,352)
Acquisition & divestitures 18,478 12 475 458 24,148
Revisions to previous estimates 9,971 471 (67) (2,822) (4,537)
Balance – December 31, 2014 839,185 9,685 36,746 36,507 1,336,809
Proved Developed Reserves as of December 31, 2014 365,673 7,628 15,238 13,977 586,733
________________
1 Unaudited 2014 production figures for the twelve months ended December 31, 2014

The following table summarizes Rex Energy’s total proved reserves by region as of December 31, 2014:

Proved Reserves by Asset Area
PDP PDNP PUD Total PV10(1)
(MMcfe) (MMcfe) (MMcfe) (MMcfe)  (M$)
Appalachia Basin
Butler Operated Area 361,806 18,994 660,507 1,041,307 $719,477
Moraine East/Western Lawrence 5,771 13,935 4,452 24,158 $28,316
Warrior Prospects 67,289 21,830 37,817 126,936 $230,828
Westmoreland, Centre, Clearfield Counties – Non-Operated 57,140 42,851 99,990 $60,737
All Other Appalachia 2,745 2,745 $2,344
Illinois Basin 36,674 548 4,450 41,673 $163,534
Total 531,425 55,307 750,077 1,336,809 $1,205,236
1 PV-10 is a non-GAAP financial measure because it excludes the effect of income taxes and asset retirement obligations. A further discussion of PV-10 as well as a reconciliation to the most directly comparable GAAP measure is included in the appendix attached to this release.

Below is a summary of the number of net wells by proved reserve classification for the company’s Appalachian Basin as of December 31, 2012, 2013 and 2014.

Total Company Net Appalachia Basin Wells
12/31/2012 12/31/2013 12/31/2014
PDP 53.6 85.0 126.7
PDNP 0.4 0.7 15.0
PUD 58.1 85.6 117.0
Total 112.1 171.3 258.7
PUD:PD Ratio 1.08 1.00 0.83
___________________

The proved undeveloped to proved developed ratio for the period ending December 31, 2014 is 0.83 to 1.

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.

Forward-Looking Statements

Certain statements made in this release 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” 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):

  • economic conditions in the United States and globally;
  • domestic and global demand for oil, NGLs and natural gas;
  • volatility in oil, NGL, and natural gas pricing;
  • new or changing government regulations, including those relating to environmental matters, permitting, or other aspects of our operations;
  • the geologic quality of the company’s properties with regard to, among other things, the existence of hydrocarbons in economic quantities;
  • uncertainties inherent in the estimates of our oil and natural gas reserves;
  • our ability to increase oil and natural gas production and income through exploration and development;
  • drilling and operating risks;
  • the success of our drilling techniques in both conventional and unconventional reservoirs;
  • the success of the secondary and tertiary recovery methods we utilize or plan to employ in the future;
  • the number of potential well locations to be drilled, the cost to drill them, and the time frame within which they will be drilled;
  • the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services;
  • the availability of equipment, such as drilling rigs, and infrastructure, such as transportation, pipelines, processing and midstream services;
  • the effects of adverse weather or other natural disasters on our operations;
  • competition in the oil and gas industry in general, and specifically in our areas of operations;
  • changes in our drilling plans and related budgets;
  • the success of prospect development and property acquisition;
  • the success of our business and financial strategies, and hedging strategies;
  • conditions in the domestic and global capital and credit markets and their effect on us;
  • the adequacy and availability of capital resources, credit, and liquidity including, but not limited to, access to additional borrowing capacity; and
  • uncertainties related to the legal and regulatory environment for our industry, and our own legal proceedings and their outcome.

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

Note on Hydrocarbon Volumes and Estimates

The estimates of proved reserves in this release are based on a reserve report of our independent external reserve engineers as of December 31, 2014. “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 (see Rule 4-10(a) of Regulation S-X for the SEC definition of “proved reserves”). The SEC permits publicly-reporting oil and gas companies to disclose “proved reserves” in their filings with the SEC. 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 use certain broad terms and other descriptions of volumes of potentially recoverable hydrocarbons in our public statements. These broad 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. We are prohibited from disclosing hydrocarbon quantities that do not constitute reserves in documents filed with the SEC.

We believe the data we prepared and supplied to our external reservoir engineers in connection with their preparation of the 12/31/2014 reserve report, and the assumptions, forecasts, and estimates contained therein, are reasonable, however, we cannot assure that they will prove to have been correct. Estimates of reserves can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.

Additional information for audited and final reserves will be provided in our Annual Report on Form 10-K for the year ended December 31, 2014currently planned to be filed with the Securities and Exchange Commission by the end of March 2015.

APPENDIX
REX ENERGY CORPORATION
NON-GAAP MEASURES

Finding and Development Cost

Finding and Development Cost per unit of production 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. Drill-Bit Finding and Development Cost is defined as the sum of total capital deployed, less lease acquisitions and other related expenditures, 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, and revisions, less the prior period’s production. The calculations presented by the company are based on unaudited costs incurred excluding estimated abandonment costs. For purposes of consistency with current calculations, we have revised certain amounts relating to prior period Capital Deployed and Finding and Development Cost. All financial results are unaudited.

A tabular presentation of Drill-Bit and All-In Capital Deployed is included below ($ in millions):

December 31, December 31, December 31,
2012 2013 2014
Drill-Bit Capital Deployed  $ 176.9  $ 283.3  $ 351.6
Acreage Acquisitions 51.0 35.6 186.3
Equity Method Investments, Noncontrolling Interests and Other1 11.0 18.7 11.9
All-In Capital Deployed  $ 238.9  $ 337.6  $ 549.8
1. Includes capitalized interest, vehicles and corporate capital

A tabular presentation of Drill-Bit Finding and Development Cost is included below ($ in millions):

December 31, December 31, December 31,
2012 2013  2014
Drill-Bit Capital Deployed  $ 176.9  $ 283.3  $ 351.6
Extensions and Discoveries (Bcfe) 196.6 312.5 523.8
Drill-Bit Finding and Development Cost ($/Mcfe)  $ 0.90  $ 0.91  $ 0.67

A tabular presentation of Drill-bit Finding and Development Cost for the Butler Operated Area is included below ($ in millions):

December 31, December 31, December 31,
2012 2013 2014
Butler Op. Area Drill-Bit Capital Deployed  $ 85.3  $ 104.4  $ 186.3
Butler Op. Area Extensions and Discoveries (Bcfe) 169.5 226.9 455.9
Butler Op. Area Drill-Bit Finding and Development Cost ($/Mcfe)  $ 0.50  $ 0.46  $ 0.41

A tabular presentation of All-in Finding and Development Cost is included below ($ in millions):

December 31, December 31, December 31,
2012 2013 2014
All-In Capital Deployed  $ 238.9  $ 337.6  $ 549.8
Extensions and Discoveries (Bcfe) 196.6 312.5 523.8
Production (Bcfe) (24.6) (33.8) (56.4)
Acquisitions and Divestitures (Bcfe) 0.3 24.1
Revisions to Previous Estimates (Bcfe) 79.6 (46.9) (4.5)
Subtotal (Bcfe) 251.9 231.8 487.0
All-In Finding and Development Cost ($/Mcfe)  $ 0.95  $ 1.46  $ 1.13

Reconciliation of Standardized Measure to PV-10

PV-10 is a non-GAAP metric used by the industry, investors and analysts to estimate of the present value, discounted at 10% per annum, of estimated future cash flows of our estimated proved reserves before income tax and asset retirement obligations The following table shows the reconciliation of PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable GAAP measure, for the years ended December 31, 2012, 2013 and 2014. Management believes that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

At December 31,
($ in millions) 2012 2013 2014
Reconciliation of Standardized Measure to PV-10
PV-10  $ 500.5  $ 668.7  $ 1,205.2
Less: Present value of future income tax discounted at 10%1 (79.6) (111.1) (96.5)
Less: Present value of future asset retirement obligations discounted at 10%1 (24.8) (28.5) (40.1)
Standardized measure of discounted future net cash flows  $ 396.1  $ 529.1  $ 1,068.6
1 For purposes of this reconciliation, we have used estimates of the effects of future income taxes and future abandonment costs (asset retirement obligations). These preliminary estimates may be revised in connection with the preparation of our financial statements for the year ended December 31, 2014.
CONTACT: For more information contact:



         Mark Aydin

         Manager, Investor Relations

         (814) 278-7249

         [email protected]

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