REX ENERGY CORP - FORM 10-K

Attached files

file	filename
EX-3.1 - CERTIFICATE OF INCORPORATION OF REX ENERGY CORPORATION - REX ENERGY CORP	dex31.htm
EX-99.1 - REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - REX ENERGY CORP	dex991.htm
EX-23.1 - CONSENT OF MALIN, BERGQUIST & COMPANY, LLP - REX ENERGY CORP	dex231.htm
EX-32.1 - SECTION 906 CEO AND CFO CERTIFICATION - REX ENERGY CORP	dex321.htm
EX-23.2 - CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - REX ENERGY CORP	dex232.htm
EX-21.1 - SUBSIDIARIES OF THE REGISTRANT - REX ENERGY CORP	dex211.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - REX ENERGY CORP	dex311.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - REX ENERGY CORP	dex312.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

Commission file number: 001-33610

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

20-8814402

(State or other Jurisdiction of

Incorporation or Organization)

(I.R.S. employer

identification number)

476 Rolling Ridge Drive, Suite 300

State College, Pennsylvania 16801

(Address of Principal Executive Offices)

(Zip Code)

(814) 278-7267

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Common Stock, $.001 par value per share		The NASDAQ Global Market

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files. Yes ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (check one):

Large Accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2009 was $144,796,353. This amount is based on the closing price of the registrant’s common stock on the NASDAQ Global Market on that date. Shares of common stock beneficially held by executive officers and directors of the registrant are not included in the computation. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

43,713,912 common shares, $.001 par value, were outstanding on March 2, 2010.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for its 2010 Annual Meeting of Stockholders to be held on May 6, 2010, are incorporated by reference herein in Items 10, 11, 12, 13 and 14 of Part III of this report.

REX ENERGY CORPORATION

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2009

TABLE OF CONTENTS


PART I		5
Item 1.	Business	5
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	32
Item 2.	Properties	32
Item 3.	Legal Proceedings	40
Item 4.	Reserved	40

PART II		41
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41
Item 6.	Selected Financial Data	43
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	63
Item 8.	Financial Statements and Supplementary Data	66
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	120
Item 9A.	Controls and Procedures	120
Item 9B.	Other Information	121

PART III		122
Item 10.	Directors, Executive Officers and Corporate Governance	122
Item 11.	Executive Compensation	122
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	122
Item 13.	Certain Relationships and Related Transactions and Director Independence	122
Item 14.	Principal Accountant Fees and Services	122

PART IV		123
Item 15.	Exhibits and Financial Statement Schedules	123

GLOSSARY		128
SIGNATURES		131

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

Some of the information, including all of the estimates and assumptions, in this report contain forward-looking statements within the meaning of Sections 27A of the Securities Act of 1933, as amended, and 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this report, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans, objectives of management for future operations, legal strategies, and legal proceedings, are forward-looking statements. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may”, “will”, “expect”, “intend”, “estimate”, “anticipate”, “believe”, or “continue” or the negative thereof or variations thereon or similar terminology.

These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking statements include, among others, the following:

•

adverse economic conditions in the United States and globally;

•

difficult and adverse conditions in the domestic and global capital and credit markets;

•

domestic and global demand for oil and natural gas;

•

volatility in the prices we receive for our oil and natural gas;

•

the effects of government regulation, permitting, and other legal requirements;

•

the quality of our properties with regard to, among other things, the existence of reserves in economic quantities;

•

uncertainties about the estimates of our oil and natural gas reserves;

•

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

•

our 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;

•

drilling and operating risks;

•

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

•

changes in our drilling plans and related budgets;

•

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

•

uncertainties associated with our legal proceedings and their outcome; and

•

other factors discussed under “Risk Factors” in Item 1A of this report.

Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of the respective document. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Most of these factors are difficult to anticipate and may be beyond our control. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

SPECIAL NOTE REGARDING THE REGISTRANT

In this report, we refer to certain companies—Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, New Albany—Indiana, LLC, PennTex Resources, L.P., PennTex Resources Illinois, Inc., Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy III LLC, Rex Energy IV, LLC, Rex Energy II Alpha Limited Partnership, Rex Energy Operating Corp. and Rex Energy Royalties Limited Partnership—collectively as the “Predecessor Companies.” In this report, we refer to each of the Predecessor Companies individually as:


Douglas Oil & Gas Limited Partnership		“Douglas Oil & Gas”
Douglas Westmoreland Limited Partnership		“Douglas Westmoreland”
Rex Energy Royalties Limited Partnership		“Rex Royalties”
Midland Exploration Limited Partnership		“Midland”
New Albany-Indiana, LLC		“New Albany”
PennTex Resources Illinois, Inc		“PennTex Illinois”
PennTex Resources, L.P		“PennTex Resources”
Rex Energy Limited Partnership		“Rex I”
Rex Energy II Limited Partnership		“Rex II”
Rex Energy II Alpha Limited Partnership		“Rex II Alpha”
Rex Energy III LLC		“Rex III”
Rex Energy IV, LLC		“Rex IV”
Rex Energy Operating Corp		“Rex Operating”

Simultaneously with the consummation of our initial public offering of common stock, through a series of mergers and reorganization transactions, which we refer to as the “Reorganization Transactions,” Rex Energy Corporation acquired all of the outstanding equity interests of the Predecessor Companies. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together with the Predecessor Companies, after giving effect to the Reorganization Transactions.

Beginning on page 128 of this report, we have included a glossary of oil and natural gas terms used throughout this report.

PART I

ITEM 1.

BUSINESS

General

We are an independent oil and gas company operating in the Appalachian Basin and the Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale drilling projects. In the Illinois Basin, in addition to our developmental conventional oil drilling, we are focused on the implementation of enhanced oil recovery on our properties. We pursue a balanced growth strategy of exploiting our sizable inventory of lower-risk developmental drilling locations, pursuing our higher potential exploration drilling prospects, and actively seeking to acquire complementary oil and natural gas properties.

We were incorporated in the state of Delaware on March 8, 2007. We completed our initial public offering and the Reorganization Transactions in July 2007. Our common stock currently trades on the NASDAQ Global Market under the symbol “REXX”. The information set forth in this report is exclusive of our discontinued operations related to the Southwest Region properties, unless otherwise noted, which are classified as Discontinued Operations on our Consolidated and Combined Statements of Operations and Assets Held for Sale on our Consolidated Balance Sheets.

At December 31, 2009, our proved reserves had the following characteristics:

•

125.2 Bcfe;

•

55.1% crude oil and natural gas liquids (“NGLs”);

•

54.2% proved developed; and

•

a reserve life index of approximately 20 years (based upon fourth quarter 2009 production).

At December 31, 2009, we operated approximately 2,134 wells. For the quarter ended December 31, 2009, we produced an average of 17.2 net MMcfe per day, composed of approximately 69.5% oil and NGLs and approximately 30.5% natural gas.

We are one of the largest oil producers in the Illinois Basin, with an average net daily production of 1,971 barrels of oil per day in 2009. In addition to our developmental shallow oil drilling in the Illinois Basin, we are in the process of implementing an enhanced oil recovery project, or EOR project, in the Lawrence Field in Lawrence County, Illinois, which we refer to as our Lawrence Field ASP Flood Project.

In our Appalachian Basin during 2009, we averaged net production of approximately 4.3 MMcfe per day of natural gas and NGLs. In 2009, we grew our reserves and production in the region through exploratory drilling, primarily through our Marcellus Shale drilling projects. As of December 31, 2009, we controlled approximately 90,000 gross (58,000 net) acres in areas of Pennsylvania that we believe are prospective for the Marcellus Shale exploration. The net acreage amount excludes approximately 22,000 acres which can be earned by Williams Production Company, LLC and Williams Production Appalachia, LLC (collectively, “Williams”) pursuant to the Participation and Exportation Agreement entered into on June 18, 2009.

Our total operating revenues for the year ended December 31, 2009 were $48.7 million. Revenues were derived from $48.5 million in oil and natural gas sales and $0.2 million in other revenues.

For the year ended December 31, 2009, we drilled 31.0 gross (28.0 net) wells. The wells drilled in 2009 include 23.0 gross (20.5 net) wells that were productive, one gross (one net) dry hole and seven gross (6.5 net) wells that are awaiting completion and are expected to be productive during the first quarter of 2010.

The following table sets forth selected data concerning our continuing operations, and our production, proved reserves and undeveloped acreage in our two operating regions for the periods indicated:


Basin/Region	Annual 2009 Average Daily Mcfe(1)	Total Proved Bcfe (As of December 31, 2009)	Percent of Total Proved Bcfe		PV-10 (As of December 31, 2009) (In Millions)(2)		Total Net Undeveloped Acres (As of December 31, 2009)(3)
Illinois Basin	11,830	61.6	49.2	%	$	145.4	6,451
Appalachian Basin	4,272	63.6	50.8	%		45.1	46,699

Total	16,102	125.2	100.0	%	$	190.5	53,150

(1)	Oil and natural gas liquids are converted at the rate of one BOE to six Mcfe.

(2)

Represents the present value, discounted at 10% per annum (PV-10), of estimated future net cash flows before income tax of our estimated proved reserves. PV-10 is a non-GAAP financial measure because it excludes the effects of income taxes and asset retirement obligations. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as defined under GAAP. At December 31, 2009, our standardized measure was $144.4 million. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, please read “Selected Financial and Operating Data—Non-GAAP Financial Measures.” Please also read “Risk Factors—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.”

(3)	Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves.

Our Competitive Strengths

We believe the combination of the following strengths is directly related to our historical successes and the future implementation of our strategy:

Significant Production Growth Opportunities: We have several projects and properties that we believe are capable of significant proved reserves and production growth. These include:

•

our Lawrence Field ASP Flood Project in Illinois (please see “Item 2. Properties—Illinois Basin—Lawrence Field ASP Flood Project”);

•

our conventional shallow oil drilling opportunities in the Illinois Basin; and

•

our large acreage position in Pennsylvania prospective for Marcellus unconventional shale exploration (please see “Item 2. Properties—Appalachian Basin—Marcellus Shale”).

Market Leader in the Illinois Basin: We are one of the largest oil producers and a market leader in the Illinois Basin, which enables us to realize a current premium over the basin-posted prices on our oil production and a competitive cost structure due to economies of scale, and provides us with a unique local knowledge of the basin. We believe these advantages may enhance our ability to continue making strategic acquisitions in the basin.

Experienced Management Team with a Proven Track Record: We believe we have significant technical and managerial experience in our core operating areas. Our senior technical team of geologists and engineers has an average of over 20 years of experience, primarily in the Illinois and Appalachian Basins. This experience and the capabilities of our management team have enabled us to build a high quality asset base of proved reserves and growth projects, both organically and through selective acquisitions.

Financial Flexibility: As of December 31, 2009, we had approximately $5.6 million of cash on hand. In addition, our senior credit facility had a borrowing capacity of $80 million as of December 31, 2009, of

which $57 million was available for working capital purposes or to fund new acquisitions. Lastly, we believe our oil and gas financial derivative activities enable us to achieve more predictable cash flows and reduce our exposure to short-term fluctuations in oil and natural gas prices while we continue to develop our properties. For a more detailed discussion of our derivative activities, see the information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

On January 21, 2010, we completed an underwritten public offering of 6,900,000 shares of our common stock, which included 900,000 shares of common stock issued upon the full exercise of the underwriters’ over-allotment option, at a public offering price of $12.25 per share. The net proceeds from the offering were approximately $80.2 million, after deducting underwriting discounts, commissions and estimated offering expenses. We intend to use the net proceeds of the offering to fund a portion of our capital expenditure program for 2010 and for other general corporate purposes. Pending these uses, we intend to use a portion of the proceeds to fully repay outstanding borrowings under our senior credit facility and invest the remainder in short-term, investment grade, interest-bearing securities.

Incentivized Management Ownership: We believe our performance is enhanced when our employees and directors think and act like owners. To achieve this, we believe in rewarding and encouraging our employees and directors through equity ownership in our company. As of March 2, 2010, our directors and officers beneficially owned approximately 26% of our outstanding common stock. Therefore, we believe that the interests of our directors and executive officers are closely aligned with those of our stockholders.

Business Strategy

Our strategy is to increase stockholder value by profitably increasing our reserves, production, cash flow and earnings. The following are key elements of our strategy:

Employ Technological Expertise: Our strategy is to utilize and expand the technological expertise that has enabled us to achieve a drilling completion rate of approximately 99% over the last three years and has helped us improve operations and enhance field recoveries. We intend to apply this expertise to our proved reserve base and our development projects.

Develop Our Existing Properties: Our focus is to develop our asset base in both of our operating basins, including:

•

our Marcellus Shale natural gas play with approximately 90,000 gross (58,000 net) acres;

•

our Lawrence Field ASP Flood Project in Illinois; and

•

our inventory of approximately 348 proved undeveloped locations and proved developed non-producing wells.

Pursue Strategic Acquisitions and Joint Ventures: We plan to continue to acquire and lease additional oil and natural gas properties in our core areas of operation. We believe that our strong history of acquisitions, leading position in the Illinois Basin and technical expertise situate us well to attract joint venture partners and pursue strategic acquisitions.

Focus on Operations: We intend to focus our future acquisition and leasing activities on properties where we have a significant working interest and can operate the property to control and implement the planned exploration and development activity.

Reduce Per Unit Operating Costs Through Economies of Scale and Efficient Operations: As we continue to increase our oil and natural gas production and develop our existing properties, we believe that our per unit production costs will benefit from increased production in lower cost operations and through better use of our existing infrastructure over a larger number of wells.

Maintain Flexibility: Because of the volatility of commodity prices and the risks involved in our industry, we believe in remaining flexible in our capital budgeting process. When appropriate, we may defer capital projects to seize an attractive acquisition opportunity or reallocate capital towards projects where we believe we can generate higher than anticipated returns. We also believe in maintaining a strong balance sheet and using commodity hedging. This allows us to be more opportunistic in lower price environments as well as providing more consistent financial results.

Significant Accomplishments in 2009

During 2009, our significant accomplishments included:

•

Exploration agreement with Williams in the Marcellus Shale: We entered into an exploration agreement with subsidiaries of Williams to pursue the development of the Marcellus Shale. Under the terms of the agreement, Williams will acquire a 50% interest in our leasehold interests in Westmoreland, Clearfield and Centre Counties in Pennsylvania, covering approximately 44,000 gross (44,000 net) acres for approximately $33.0 million through a “drill to earn” structure. Williams will bear 90% of all costs and expenses incurred in the drilling and completion of all wells jointly drilled in the project areas until such time as Williams has invested $74 million ($33 million on behalf of Rex Energy and $41 million for Williams’ 50% share of the wells).

•

Horizontal drilling success: We successfully drilled and completed at least one horizontal well in each of our Marcellus Shale project areas with at least 3 Bcfe EUR.

•

Decrease in lease operating expenses: We decreased our lease operating expenses, on a per unit of production basis, by approximately 19.0% when compared to 2008.

•

Completed divestiture of Southwestern Region assets: We successfully completed the sale of our Southwestern Region assets for net cash proceeds of approximately $17.3 million. The sale of these non-core assets was a part of our strategic plan to focus efforts on Marcellus Shale drilling projects in the Appalachian Basin and the Lawrence Field ASP Flood Project in the Illinois Basin.

•

Production growth: Due to our Marcellus Shale drilling program, we increased our natural gas production by 50.4% over 2008.

•

Reserves growth: Our proved reserves in the Appalachian Basin, which consist of 100% natural gas and NGLs, increased approximately 106% from 2008 year-end estimates. In the Illinois Basin, our proved reserves, which consist of 100% crude oil, increased approximately 74% from 2008 year-end estimates.

•

Midstream joint venture: We entered a midstream joint venture during 2009 with Stonehenge Energy Resources, L.P. that will initially invest up to $25.0 million to build a high pressure gathering system and cryogenic gas processing plant in Butler County, Pennsylvania.

•

Balance Sheet strength: As of December 31, 2009, we maintained a debt-to-capital ratio of approximately 9.6%.

•

Continued Expansion of Drilling Inventory: To continue to grow, the size of our prospect inventory must remain large. Our drilling inventory currently includes approximately 1,300 proved, probable and possible drilling locations. As of December 31, 2009, we controlled approximately 90,000 gross (58,000 net) acres in the Marcellus Shale play in Pennsylvania. The net acreage amount excludes approximately 22,000 acres which can be earned by Williams pursuant to the Participation and Exportation Agreement entered into on June 18, 2009.

Plans for 2010

In December 2009, our board of directors approved a 2010 capital budget of approximately $100.1 million. The 2010 capital budget reflects our commitment to creating shareholder value based on what we believe to be our highest potential projects. Our 2010 capital budget will allow us to drill approximately 10 gross (10 net)

horizontal Marcellus Shale wells in Butler County, Pennsylvania and an additional nine gross (4.5 net) horizontal wells in the joint venture project areas with Williams. In our Illinois Basin, we anticipate drilling 10 to 15 (gross and net) shallow conventional oil wells. Additionally, we will also begin chemical injection on the first operationally sized ASP unit. Our board of directors also approved an option to spend an additional $34.8 million on leasing activities should market conditions require additional capital to obtain oil and gas leases.

Other operational plans for 2010 and beyond include water treatment and gas processing services. Our water treatment services will include acquiring, managing and operating water treatment, water disposal and water transportation facilities that are designed to treat, dispose or transport brine and other waters produced in oil and gas well development activities. Our gas processing services will be principally focused on building, operating and owning a high pressure gathering system and cryogenic gas processing plant in Butler County, Pennsylvania. Budgeted capital expenditures for water treatment and gas processing services in 2010 total approximately $22.0 million. For additional information on these activities, see Note 1, Basis of Presentation and Principles of Consolidation, to our Consolidated and Combined Financial Statements.

The following table summarizes our actual 2009 and our budgeted 2010 capital expenditures ($ in millions). The estimated capital expenditures are dependent on a number of factors, including industry conditions and our drilling success, and are subject to change. We do not attempt to budget for future acquisitions of proved oil and gas properties.


	For the Years Ended December 31,
	2009 (actual)		2010 (estimated)
Capital Expenditures
Illinois Basin Conventional Oil Operations	$	6.8	$	10.1
ASP Flood Project Drilling & Facility		3.3		7.9
Marcellus Shale Projects		20.6		66.0
Appalachian Basin Operations		0.6		—
Acquisitions and leasing of undeveloped properties		17.9		15.9	(1)
Other Capital Expenditures		1.7		0.2

Total Capital Expenditures	$	50.9	$	100.1

(1)	Does not include the authorization from our board of directors to spend an additional $34.8 million on leasing activities.

Production, Revenues and Price History

The following table sets forth information regarding oil and gas production and revenues for continuing operations for the last three years ($ in thousands):


	Production and Revenue by Region For the Years Ended December 31,
	2009		2008		2007
Appalachian Region:
Revenue	$	6,671	$	9,783	$	5,725
Oil Production (Bbls)		358		—		—
Natural Gas Production (Mcf)		1,510,500		1,036,891		786,095
NGL Production (Bbls)		7,750		—		—
Total Production (Mcfe)(1)		1,559,148		1,036,891		786,095
Oil Average Sales Price	$	50.28	$	—	$	—
Natural Gas Average Sales Price	$	4.28	$	9.43	$	7.28
NGL Average Sales Price	$	24.90	$	—	$	—

Illinois Region:
Revenue	$	41,863	$	74,230	$	52,408
Oil Production (Bbls)		719,652		776,185		769,911
Natural Gas Production (Mcf)		—		—		—
NGL Production (Bbls)		—		—		—
Total Production (Bbls)		719,652		776,185		769,911
Oil Average Sales Price	$	58.17	$	95.63	$	68.07
Natural Gas Average Sales Price	$	—	$	—	$	—
NGL Average Sales Price	$	—	$	—	$	—

Total Company:
Revenue	$	48,534	$	84,013	$	58,133
Oil Production (Bbls)		720,010		776,185		769,911
Natural Gas Production (Mcf)		1,510,500		1,036,891		786,095
NGL Production (Bbls)		7,750		—		—
Total Production (Mcfe)(1)		5,877,060		5,694,001		5,405,561
Oil Average Sales Price	$	58.17	$	95.63	$	68.07
Natural Gas Average Sales Price	$	4.28	$	9.43	$	7.28
NGL Average Sales Price	$	24.90	$	—	$	—

(1)	Oil and NGLs are converted at the rate of one BOE to six Mcfe.

Competition

The oil and gas industry is intensely competitive, particularly with respect to the acquisition of prospective oil and natural gas properties and oil and natural gas reserves. Our ability to effectively compete is dependent on our geological, geophysical and engineering expertise and our financial resources. We must compete against a substantial number of major and independent oil and natural gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, market refined products and generate electricity. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment necessary for drilling and completion of wells. Consequently, drilling equipment may be in short supply from time to time. Additionally, it is difficult to attract and retain employees, particularly those with expertise in high demand areas.

Employees

As of December 31, 2009, we had 163 full-time employees, 96 of whom were field personnel. No employees are covered by a labor union or other collective bargaining arrangement. We believe that our relations with our employees are good. We regularly utilize independent consultants and contractors to perform various professional services, particularly in the areas of drilling, completion, field services, oil and gas leasing, and on-site production operation services.

Marketing and Customers

We market nearly all of our oil and gas production from the properties we operate for both our interest and that of the other working interest owners and royalty owners.

In the Illinois Basin, the majority of our oil is stored at well site tanks and sold to CountryMark Cooperative, LLP (“CountryMark”), a local refinery, currently at a premium to the basin-posted prices. This premium is provided to us due to our significant size in the basin relative to other local producers. The oil is purchased at our tank facilities from the refiner and trucked to refinery facilities. The revenue we derived from our sales to CountryMark for the year ended December 31, 2009 constituted approximately 77% of our oil and natural gas sales revenue from continuing operations for such period. As such, we are currently significantly dependent on the creditworthiness of CountryMark. We have taken steps to monitor the creditworthiness of CountryMark, including obtaining a letter of credit corresponding to a significant projected monthly revenue. For additional information, see “Risk Factors—We depend on a relatively small number of customers for a substantial portion of our revenue. The inability of one or more of our purchasers to meet their obligations or the loss of our market with CountryMark Cooperative, LLP, in particular, may adversely affect our financial results,” in Item 1A of this report.

On December 30, 2009, we entered into a Master Crude Purchase Agreement (the “Master Crude Purchase Agreement”) with CountryMark. The agreement was effective as of January 1, 2010 and replaced in its entirety a letter agreement in place between us and CountryMark regarding crude oil purchases. Under the terms of the agreement, we agreed to sell, supply and deliver to CountryMark, and CountryMark agreed to receive and purchase from us, crude oil pursuant to purchase and sale order confirmations that we and CountryMark may enter into from time to time. Under the agreement, until we enter into a confirmation with CountryMark, neither party is under an obligation to purchase or sell any crude oil. Under the terms of the Master Crude Purchase Agreement, at least 120 days prior to the beginning of each calendar year, CountryMark is required to provide written notice to us stating the quantity, specifications and crude price for the crude oil that CountryMark wishes to purchase from us for the upcoming term commencing on January 1 of such year. If these terms and conditions are acceptable to us, we may enter into a written confirmation with CountryMark setting forth this agreement. Each confirmation will also set forth the price to be paid by CountryMark to us for each barrel of oil sold to CountryMark during the term of such confirmation and the oil and gas leases from which we will sell to CountryMark all crude oil produced and trucked during the term of the confirmation. The term of the Master Crude Purchase Agreement commences on January 1, 2010 and will terminate on January 1, 2011, provided that the term will automatically be extended for additional one-year terms unless, prior to October 1 of each year, either party gives written notice to the other. In connection with the execution of the Master Crude Purchase Agreement, we entered into Confirmation Number 1 with CountryMark for the period commencing on January 1, 2010 and ending on December 31, 2010. Pursuant to the Confirmation Number 1, CountryMark agreed to purchase all crude oil produced by us from a substantial majority of our oil and gas leases covering lands in the Illinois Basin.

During 2008, we constructed our own offload facility at a nearby crude oil pipeline operated by Marathon Oil Corp. that has enabled us to slightly diversify our purchasers. In the Appalachian Basin, our natural gas producing properties are located near existing pipeline systems and processing infrastructure. The majority of our production is transported over our own gathering lines to local distribution companies. For additional information, see “Risk Factors—We depend on pipelines owned by others to transport and sell our natural gas

production. Disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our natural gas,” in Item 1A of this report. In the Appalachian Basin, due to its proximity to large east coast cities, we have generally received a premium over market prices for our gas production of approximately $0.25-$0.50 per Mcf.

We are in the process, in conjunction with a third-party partner, of constructing a high pressure gathering system and a cryogenic gas processing plant in Butler County, Pennsylvania. We expect that the cryogenic gas processing plant will service our wells and third-party wells in the area that produce natural gas with a high BTU content. The cryogenic gas processing plant is expected to decrease the BTU level of the gas to appropriate levels for distribution through a standard sales line. The by-products of the cryogenic gas processing plant are natural gas liquids which will be marketed separately. For further information on our midstream services, see Note 1, Basis of Presentation and Principles of Consolidation, to our Consolidated and Combined Financial Statements.

Prices for oil and natural gas fluctuate widely based on, among other things, supply and demand. Supply and demand are influenced by a number of factors, including weather, foreign policy, industry practices and the U.S. and worldwide economic climate. Oil and natural gas markets have historically been cyclical and volatile in nature as a result of many factors that are beyond our control. There can be no assurance of what price we will be able to sell our oil and natural gas. Prices may be low when our wells are most productive, thereby reducing overall returns.

We enter into derivative transactions with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and gas prices. For a more detailed discussion, see the information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

Governmental Regulations

Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, some states in which we operate require permits for drilling operations, drilling bonds or reports concerning operations, and impose other requirements relating to the exploration for and production of oil and natural gas. In addition, states in which we operate may have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of wells. Failure to comply with any such rules or regulations can result in substantial penalties. The increasing regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. We may be required to make significant expenditures to comply with governmental laws and regulations, which could have a material adverse effect on our business, financial condition and results of operations.

Our operations are subject to various types of regulation at the federal, state and local levels that:

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require permits for the drilling of wells, which generally require a minimum of 45-120 days to obtain;

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require permits to drill wells on federal lands, which generally require a minimum of 60-120 days to obtain;

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require permits to drill wells on state land and fee lands, which generally require a minimum of 30-60 days to obtain;

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mandate that we maintain bonding requirements in order to drill or operate wells; and

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regulate the location of wells, the method of drilling and casing wells, the surface development, use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, temporary storage tank operations, air emissions from flaring, compression and access roads, the impoundment of water, the manner and extent of earth disturbances, air emissions, sour gas management, the disposal of fluids used in connection with operations, and the calculation and distribution of royalty payments and production taxes.

Our operations are also subject to various conservation laws and regulations. These regulations govern the size of drilling and spacing units or proration units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of natural gas and oil properties. In this regard, some states allow the forced pooling or integration of lands and leases to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, some state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities that must be addressed before those activities can proceed. The effect of all these regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Where our operations are located on federal lands, the timing and scope of development may be limited by the National Environmental Policy Act. The regulatory burden on the oil and natural gas industry increases our costs of doing business and, consequently, affects our profitability. Because these laws and regulations are frequently expanded, amended and reinterpreted, we are unable to predict the future cost or impact of complying with applicable environmental and conservation requirements.

The Federal Energy Regulatory Commission, or FERC, regulates interstate natural gas transportation rates and service conditions. Its regulations affect the marketing of natural gas produced by us, as well as the revenues that may be received by us for sales of such production. Since the mid-1980s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B, collectively, Order 636, that have significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other services such pipelines previously performed. One of FERC’s purposes in issuing Order 636 was to increase competition within the natural gas industry. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation service, and has substantially increased competition and volatility in natural gas markets.

The price we receive from the sale of oil and natural gas liquids will be affected by the cost of transporting products to markets. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, index such rates to inflation, subject to certain conditions and limitations. We are unable to predict the effect, if any, of these regulations on our intended operations. The regulations may, however, increase transportation costs or reduce well head prices for oil and natural gas liquids.

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection and the discharge of materials into the environment. These laws and regulations:

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require the acquisition of permits or other authorizations before construction, drilling and certain other of our activities;

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limit or prohibit construction, drilling and other activities on specified lands within wilderness and other protected areas; and

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impose substantial liabilities for pollution that may result from our operations.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce environmental laws and regulations, and violations may result in fines, injunctions, or even criminal penalties. Some states continue to adopt new regulations and permit requirements, which may impede or delay our operations or increase our costs. We believe that we are in substantial compliance with current applicable environmental laws and regulations, and, except for those matters described in “Item 3. Legal Proceedings,” have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, the trend in environmental legislation and regulation generally is toward stricter standards, and we expect that this trend will continue. Changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry as a whole.

The following is a summary of the existing laws and regulations that could have a material impact on our business operations.

The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial condition.

The Comprehensive Environmental, Response, Compensation, and Liability Act, as amended, or CERCLA, and comparable state statutes impose strict liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. This liability may be joint and several and include liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production, and produced water disposal operations for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been disposed of or released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and

state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Our oil and natural gas exploration and production operations generate produced water as a waste material, which is subject to the disposal requirements of the Clean Water Act, the Safe Drinking Water Act, or SDWA, or an equivalent state regulatory program. This produced water is disposed of by re-injection into the subsurface through disposal wells, treatment and discharge to the surface, or in evaporation ponds. Whichever disposal method is used, produced water must be disposed of in compliance with permits issued by regulatory agencies, and in compliance with applicable environmental regulations. This water can sometimes be disposed of by discharging it under discharge permits issued pursuant to the Clean Water Act or an equivalent state program. Another common method of produced water disposal is subsurface injection in disposal wells. Such disposal wells are permitted under the SDWA, or an equivalent state regulatory program. To date, we believe that all necessary surface discharge or disposal well permits have been obtained and that the produced water has been discharged into the produced water disposal wells in substantial compliance with such obtained permits and applicable laws and regulations.

The Federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations.

The National Environmental Policy Act, or NEPA, requires a thorough review of the environmental impacts of “major federal actions” and a determination of whether proposed actions on federal land would result in “significant impact.” In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. NEPA review can increase the time for obtaining approval of, and impose additional regulatory burdens on, our exploration and production activities on federal lands, thereby increasing our costs of doing business and decreasing our profitability.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly reporting, waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering climate change-related legislation to restrict greenhouse gas emissions. At least ten states in the Northeast (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) and seven states in the West (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.

On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, or ACESA, which would establish an economy-wide cap-and-trade program to reduce emissions of greenhouse gases in the United States, including carbon dioxide and methane. The U.S. Senate has begun work on its own legislation for controlling and reducing greenhouse gas emissions in the United States. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation, how any bill passed by the Senate would be reconciled with ACESA, or how federal legislation may be reconciled with

state and regional requirements, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that we produce.

In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gas emissions may be regulated as an “air pollutant” under the federal Clean Air Act. On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA also proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010.

Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our business, financial condition and results of operation. In addition, these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect demand for our products and services, which may in turn adversely affect our future results of operations.

Available Information

We maintain an internet website under the name “www.rexenergy.com.” We make available, free of charge, on our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the Securities and Exchange Commission (“SEC”). Our Corporate Governance Policy, the charters of the Audit Committee, the Compensation Committee and the Nominating and Governance Committee, and the Code of Ethics for directors, officers, employees and financial officers are also available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 476 Rolling Ridge Drive, Suite 300, State College, PA 16801.

We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Rex Energy Corporation, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov. Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

ITEM 1A.

RISK FACTORS

In evaluating our company, the factors described below should be considered carefully. The occurrence of one or more of these events could significantly and adversely affect our business, prospects, financial condition, results of operations and cash flows.

Risks Related to Our Company

Future economic conditions in the U.S. and global markets may have a material adverse impact on our business and financial condition that we currently cannot predict.

The U.S. and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. While economic growth has resumed, it remains modest and the timing of an economic recovery is uncertain. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years. Unemployment rates remain high and businesses and consumer confidence levels have not yet fully recovered to pre-recession levels. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including for oil and natural gas. A lower future economic growth rate will result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

Volatility in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

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the current uncertainty in the global economy;

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changes in global supply and demand for oil and natural gas;

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the condition of the U.S. and global economy;

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the actions of certain foreign states;

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the price and quantity of imports of foreign oil and natural gas;

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political conditions, including embargoes, in or affecting other oil producing activities;

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the level of global oil and natural gas exploration and production activity;

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the level of global oil and natural gas inventories;

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production or pricing decisions made by the Organization of Petroleum Exporting Countries (“OPEC”);

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weather conditions;

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availability of limited refining facilities in the Illinois Basin reducing competition and resulting in lower regional oil prices than in other U.S. oil producing regions;

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technological advances affecting energy consumption; and

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the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can produce economically. The higher operating costs associated with many of our oil fields will make our profitability more sensitive to oil price declines. A sustained decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Enhanced Oil Recovery, or EOR, techniques that we may use, such as our Alkali-Surfactant-Polymer flooding in the Lawrence Field, involve more risk than traditional waterflooding.

An EOR technique such as alkali-surfactant-polymer, or ASP, chemical injection involves significant capital investment and an extended period of time, generally a year or longer, from the initial phase of a pilot program until increased production occurs. The results of any successful pilot program may not be indicative of actual results achieved in a broader EOR project in the same field or area. Generally, surfactant polymer, including ASP, injection is regarded as involving more risk than traditional waterflood operations. The potential reserves associated with our ASP project in the Lawrence Field are not considered proved. Our ability to achieve commercial production and recognize proved reserves from our EOR projects is greatly contingent upon many inherent uncertainties associated with EOR technology, including ASP technology, geological uncertainties, chemical and equipment availability, rig availability and many other factors.

We have limited experience in drilling wells to the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale than in other areas of our operations. Wells drilled to the Marcellus Shale are deeper, more expensive and more susceptible to mechanical problems in drilling and completing than wells in the other areas.

We have limited experience in the drilling and completion of Marcellus Shale wells. As of December 31, 2009, we have drilled eight gross vertical wells and seven gross horizontal wells to the Marcellus Shale. Other operators in the Appalachian Basin have significantly more experience in the drilling of Marcellus Shale wells, including the drilling of horizontal wells. In addition, we have much less information with respect to the ultimate recoverable reserves and production decline rates than we have in our other areas of operation. The wells drilled in the Marcellus Shale are drilled deeper than in our other primary areas, which makes the Marcellus Shale wells more expensive to drill and complete. The wells will also be more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. The fracturing of the Marcellus Shale will be more extensive and complicated than fracturing other geological formations in our other areas of operation and requires greater volumes of water than conventional gas wells. The management of water and treatment of produced water from Marcellus Shale wells may be more costly than the management of produced water from other geologic formations.

If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell natural gas and/or receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas may have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

If drilling in the Marcellus Shale areas continues to be successful, the amount of natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for the Marcellus Shale area may not occur for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.

A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

If we are unable to acquire adequate supplies of water for our Marcellus Shale drilling operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.

We use between three and four million gallons of water per well in our Marcellus Shale well completion operations. Our inability to locate sufficient amounts of water, or dispose of water after drilling, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Furthermore, new environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may also increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

Among the changes contained in President Obama’s 2011 budget proposal, released by the White House on February 1, 2010, is the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of any legislation as a result of the budget proposal, the Senate bill, or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Enactment of a Pennsylvania severance tax on natural gas could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in Pennsylvania.

As a result of a funding gap in the Pennsylvania state budget due to significant declines in anticipated revenue, the governor of the Commonwealth of Pennsylvania has proposed to its legislature the adoption of a severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax is five percent of the value of the natural gas at the wellhead, plus 4.7 cents per thousand cubic feet of natural gas severed. All of our Marcellus Shale acreage is located in the Commonwealth of Pennsylvania. If Pennsylvania adopts such a severance tax, it could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in Pennsylvania.

All of the value of our production and reserves is concentrated in the Illinois Basin and Appalachian Basin. Because of this concentration, any production problems or changes in assumptions affecting our proved reserve estimates related to these areas could have a material adverse impact our business.

For the year ended December 31, 2009, 73.5% of our net daily production came from the Illinois Basin area and 26.5% came from the Appalachian Basin. As of December 31, 2009, approximately 49.2% of our proved reserves were located in the fields that comprise the Illinois Basin and 50.8% of our proved reserves were a result of our Appalachian Basin operations. If mechanical problems, weather conditions or other events were to curtail a substantial portion of the production in one or both of these regions, our cash flow could be adversely affected. If ultimate production associated with these properties is less than our estimated reserves, or changes in pricing, cost or recovery assumptions in the area results in a downward revision of any estimated reserves in these properties, our business, financial condition and results of operations could be adversely affected.

We depend on a relatively small number of purchasers for a substantial portion of our revenue. The inability of one or more of our purchasers to meet their obligations or the loss of our market with CountryMark Cooperative, LLP, in particular, may adversely affect our financial results.

We derive a significant amount of our revenue from a relatively small number of purchasers. While a portion of our oil in the Illinois Basin is sold through an offload facility, a majority of the oil is sold to one refinery, CountryMark Cooperative, LLP. The revenue we received from sales of our oil to CountryMark Cooperative, LLP for the year ended December 31, 2009, constituted approximately 77% of our total oil and natural gas sales revenue from continuing operations for such period. Our inability to continue to provide services to key customers, if not offset by additional sales to our other customers, could adversely affect our financial condition and results of operations. These companies may not provide the same level of our revenue in the future for a variety of reasons, including their lack of funding, a strategic shift on their part in moving to different geographic areas in which we do not operate or our failure to meet their performance criteria. The loss of all or a significant part of this revenue would adversely affect our financial condition and results of operations.

Our results of operations and cash flow may be adversely affected by risks associated with our oil and gas financial derivative activities, and our oil and gas financial derivative activities may limit potential gains.

We have entered into, and we expect to enter into in the future, oil and gas financial derivative arrangements corresponding to a significant portion of our oil and natural gas production. Many derivative instruments that we employ require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. During the twelve months ended December 31, 2009, we incurred realized gains of $10.4 million from our financial derivatives. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

If our actual production and sales for any period are less than the corresponding volume of derivative contracts for that period (including reductions in production due to operational delays), or if we are unable to perform our activities as planned, we might be forced to satisfy all or a portion of our derivative obligations

without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. In addition, our oil and gas financial derivative activities can result in substantial losses. Such losses could occur under various circumstances, including any circumstance in which a counterparty does not perform its obligations under the applicable derivative arrangement, the arrangement is imperfect or our derivative policies and procedures are not followed or do not work as planned. Under the terms of our senior credit facility with KeyBank National Association, the percentage of our total production volumes with respect to which we will be allowed to enter into derivative contracts is limited, and we therefore retain the risk of a price decrease for our remaining production volume.

If oil and natural gas prices decline, we may be required to take additional write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.

There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and stockholders’ equity.

Additional write downs could occur if oil and gas prices decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. It is likely that the cumulative effect of a write-down could also negatively impact the value of our securities, including our common stock.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

We review our oil and gas properties for impairment annually or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the book values associated with oil and gas properties.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “Item 1A. Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves” below for a discussion of the uncertainties involved in these processes. Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:

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delays imposed by or resulting from compliance with regulatory requirements;

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unusual or unexpected geological formations;

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pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel;

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equipment malfunctions, failures or accidents;

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unexpected operational events and drilling conditions;

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pipe or cement failures;

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casing collapses;

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lost or damaged oilfield drilling and service tools;

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loss of drilling fluid circulation;

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uncontrollable flows of oil, natural gas and fluids;

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fires and natural disasters;

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environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

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adverse weather conditions;

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reductions in oil and natural gas prices;

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oil and natural gas property title problems; and

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market limitations for oil and natural gas.

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.

Our proved reserves and related PV-10 as of December 31, 2009 have been reported under new SEC rules that went into effect on January 1, 2010. The estimates provided in accordance with the new SEC rules may change materially as a result of interpretive guidance that may be released by the SEC.

We have included in this report certain estimates of our proved reserves and related PV-10 at December 31, 2009 as prepared consistent with our independent reserve engineers’ interpretations of the new SEC rules relating to disclosures of estimated natural gas and oil reserves. These new rules are effective for fiscal years ending on or after December 31, 2009. These newly adopted rules will require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. The SEC has not reviewed our reserve estimates under the new rules and has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules. Accordingly, while the estimates of our proved reserves and related PV-10 at December 31, 2009 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.

We may be limited in our ability to book additional proved undeveloped reserves under the new SEC rules.

Another impact of the new SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

Estimates of oil and natural gas reserves are inherently imprecise. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. To prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

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actual prices we receive for oil and natural gas;

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actual cost of development and production expenditures;

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the amount and timing of actual production;

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supply of and demand for oil and natural gas; and

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changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our prospects are in various stages of evaluation. There is no way to predict with certainty in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable, particularly in light of the current economic environment. The use of seismic data and other technologies, and the study of producing fields in the same area, will not enable us to know conclusively before drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercially viable quantities. Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.

We cannot control activities on properties that we do not operate and are unable to control their proper operation and profitability.

We do not operate all of the properties in which we own an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:

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nature and timing of drilling and operational activities;

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timing and amount of capital expenditures;

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expertise and financial resources;

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the approval of other participants in drilling wells; and

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selection of suitable technology.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending on reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

Our future acquisitions may yield revenue or production that varies significantly from our projections.

In acquiring producing properties, we will assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact, and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems

are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for, and development, production and acquisition of, oil and natural gas reserves. To date, we have financed capital expenditures primarily with proceeds from bank borrowings, cash generated by operations and public stock offerings. We intend to finance our capital expenditures with the sale of equity, asset sales, cash flow from operations and current and new financing arrangements. Our cash flow from operations and access to capital is subject to a number of variables, including:

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our proved reserves;

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the level of oil and natural gas we are able to produce from existing wells;

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the prices at which oil and natural gas are sold; and

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our ability to acquire, locate and produce new reserves.

If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may need to seek additional financing in the future. In addition, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves. Also, our credit facility contains covenants that restrict our ability to, among other things, materially change our business, approve and distribute dividends, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

We may, from time to time, encounter difficulty in obtaining, or an increase in the cost of securing, drilling rigs, equipment and supplies. In addition, larger producers may be more likely to secure access to such equipment by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reserves could increase significantly, which would adversely affect our financial condition and results of operations.

We depend on pipelines owned by others to transport and sell our natural gas production. Disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our natural gas.

In many instances, we transport our natural gas to market by utilizing pipelines owned by others. If pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly curtailed or disrupted, we may have to reduce sales of our production of gas because we do not have facilities to store excess inventory. If this occurs, our revenues will be reduced, and our unit costs will also increase. In addition, if pipeline gas quality requirements change for a pipeline, we might be required to install

additional processing equipment, which could increase our costs. If this should occur, the pipeline could curtail our gas flows until the gas delivered to their pipeline is in compliance.

New technologies may cause our current exploration and drilling methods to become obsolete.

The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations, and we may not have enough insurance to cover all of the risks that we face.

We maintain insurance coverage against some, but not all, potential losses to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, it is not possible to insure fully against pollution and environmental risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition and results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

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abnormally pressured formations;

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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses;

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fires and explosions;

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personal injuries and death; and

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natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us. If a significant accident or other event occurs and is not fully covered by insurance, then that accident or other event could adversely affect our financial condition, results of operations and cash flows.

Our business may suffer if we lose key personnel.

Our operations depend on the continuing efforts of our executive officers and senior management. Our business or prospects could be adversely affected if any of these persons does not continue in their management role with us and we are unable to attract and retain qualified replacements. Additionally, we do not carry key person insurance for any of our executive officers or senior management.

We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

The exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, and local laws and regulations. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation are:

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the location and spacing of wells;

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the unitization and pooling of properties;

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the method of drilling and completing wells;

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the surface use and restoration of properties upon which wells are drilled;

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the plugging and abandoning of wells;

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the disposal of fluids used or other wastes generated in connection with our drilling operations;

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the marketing, transportation and reporting of production; and

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the valuation and payment of royalties.

Under these laws, we could be subject to claims for personal injury or property damages, including natural resource damages, which may result from the impacts of our operations. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs of compliance. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition and results of operations.

We must obtain governmental permits and approvals for our drilling and mid-stream operations, which can be a costly and time consuming process, which may result in delays and restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of natural gas or oil may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

Our operations expose us to substantial costs and liabilities with respect to environmental matters.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations governing the release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with our drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution that may result from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory or remedial obligations or injunctive relief. Under existing environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the release resulted from our operations, or our operations were in compliance with all applicable laws at the time they were performed.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our competitive position, financial condition and results of operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas wells in shale formations. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of two companion bills, which are currently pending in the House Energy and Commerce Committee and the Senate Committee on Environment and Public Works Committee have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, this legislation, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult and more expensive to complete natural gas wells in shale formations and increase our costs of compliance and doing business.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce.

A variety of regulatory developments, proposals or requirements and legislative initiatives have been introduced in the United States that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, or ACESA, which would establish an economy-wide cap-and-trade program to reduce emissions of greenhouse gases in the United States, including carbon dioxide and methane. The U.S. Senate has begun work on its own legislation for controlling and reducing greenhouse gas emissions in the United States. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation, how any bill passed by the Senate would be reconciled with ACESA, or how federal legislation may be reconciled with state and regional requirements, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that we produce.

In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gas emissions may be regulated as an “air pollutant” under the federal Clean Air Act. On December 15, 2009, the U.S. Environmental Protection Agency, or EPA, officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA also proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010.

The adoption of derivatives legislation by Congress and related regulations could have an adverse impact on our ability to hedge risks associated with our business.

The U.S. Congress is currently considering legislation to increase the regulatory oversight of the over-the-counter derivatives markets in order to promote more transparency in those markets, and impose restrictions on certain derivatives transactions, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission (CFTC) to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any new laws or regulations in this area may result in increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and otherwise manage our financial risks related to swings in oil and gas commodity prices, may impose additional restrictions on our trading and commodity positions, and could have an adverse effect on our ability to hedge risks associated with our business and on the cost of our hedging activity.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

The outcome of litigation in which we have been named as a defendant is unpredictable and an adverse decision in any such matter could have a material adverse effect on our financial position or results of operations.

We are defendants in a number of litigation matters and are subject to various other claims, demands and investigations. These matters may divert financial and management resources that would otherwise be used to benefit our operations. No assurances can be given that the results of these matters will be favorable to us. An adverse resolution or outcome of any of these lawsuits, claims, demands or investigations could have a negative impact on our financial condition, results of operations and liquidity.

Risks Related to Our Common Stock

Since our initial public offering on July 30, 2007, the price of our common stock has fluctuated substantially and may fluctuate substantially in the future.

Since our initial public offering on July 30, 2007, the price of our common stock has fluctuated substantially. From July 30, 2007 to March 2, 2010, the trading price of our common stock ranged from a low of $0.99 per share to a high of $29.92 per share. We expect our common stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:

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changes in oil and natural gas prices;

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variations in quarterly drilling, recompletions, acquisitions, and operating results;

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changes in financial estimates by securities analysts;

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changes in market valuations of comparable companies;

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additions or departures of key personnel;

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future issuances of our stock; and

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the other risks and uncertainties described in this “Risk Factors” section and elsewhere in this report.

We may fail to meet the expectations of our stockholders or of securities analysts at some time in the future, and our stock price could decline as a result. Volatility or depressed market prices of our common stock could make it difficult for you to resell shares of our common stock when you want or at attractive prices.

We may issue additional common stock in the future, which would dilute our existing stockholders.

In the future we may issue our previously authorized and unissued securities, including shares of our common stock or securities convertible into or exchangeable for our common stock, resulting in the dilution of the ownership interests of our stockholders. We are authorized under our amended and restated certificate of incorporation to issue 100,000,000 shares of common stock and 100,000 shares of preferred stock with such designations, preferences, and rights as may be determined by our board of directors. As of March 2, 2010, there were 43,713,912 shares of our common stock issued and outstanding and there were no shares of our preferred stock issued and outstanding.

We have an effective shelf registration statement from which additional shares of our common stock and other securities can be issued. In addition, we may also issue additional shares of our common stock or securities convertible into or exchangeable for our common stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes or for other business purposes. Future issuances of our common stock, or the perception that such issuances could occur, could have a material adverse effect on the price of our common stock.

Our amended and restated certificate of incorporation, amended and restated bylaws, and Delaware law contain provisions that could make it more difficult for a third party to acquire us without the consent of our board of directors and our Chairman and other executive officers, who collectively beneficially own approximately 26% of the outstanding shares of our common stock as of March 2, 2010.

Provisions in our amended and restated certificate of incorporation and amended and restated bylaws could have the effect of delaying or preventing a change of control of us and changes in our management. These provisions include the following:

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the ability of our board of directors to issue shares of our common stock and preferred stock without stockholder approval;

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the ability of our board of directors to make, alter, or repeal our bylaws without further stockholder approval;

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the requirement for advance notice of director nominations to our board of directors and for proposing other matters to be acted upon at stockholder meetings;

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the prohibition on stockholders taking action by written consent;

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requiring that special meetings of stockholders be called only by our Chairman, by a majority of our board of directors, by our Chief Executive Officer or by our President; and

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allowing our directors, and not our stockholders, to fill vacancies on the board of directors, including vacancies resulting from removal or enlargement of the board of directors.

In addition, we are subject to the provisions of Section 203 of the Delaware General Corporation Law. These provisions may prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us.

As of March 2, 2010, our board of directors, including Lance T. Shaner, our Chairman, and our other executive officers collectively own approximately 26% of the outstanding shares of our common stock. Although this is not a majority of our outstanding common stock, these stockholders, acting together, will have the ability to exert substantial influence over all matters requiring stockholder approval, including the election and removal of directors, any proposed merger, consolidation, or sale of all or substantially all of our assets and other corporate transactions.

The provisions in our amended and restated certificate of incorporation and amended and restated bylaws and under Delaware law, and the concentrated ownership of our common stock by our Chairman and other executive officers, could discourage potential takeover attempts and could reduce the price that investors might be willing to pay for shares of our common stock.

Because we have no plans to pay dividends on our common stock, stockholders must look solely to appreciation of our common stock to realize a gain on their investments.

We do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our senior credit facility limits the payment of dividends without the prior written consent of the lenders. Accordingly, stockholders must look solely to appreciation of our common stock to realize a gain on their investment. This appreciation may not occur.

We are able to issue shares of preferred stock with greater rights than our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our

stockholders. Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, liquidation rights, or voting rights. If we issue preferred stock, it may adversely affect the market price of our common stock.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

As of the date of this filing, we have no unresolved comments from the staff of the SEC.

ITEM 2.

PROPERTIES

The table below summarizes certain data for our core operating areas for the year ended December 31, 2009:


Division	Average Daily Production (Mcfe per day)	Total Production (Mcfe)	Percentage of Total Production		Total Proved Reserves (Mcfe)	Percentage of Total Proved Reserves
Illinois Basin	11,830	4,317,912	73.5	%	61,664,742	49.2	%
Appalachian Basin	4,272	1,559,148	26.5	%	63,558,326	50.8	%

Totals	16,102	5,877,060	100.0	%	125,223,068	100.0	%

Segment reporting is not applicable to us, as we have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis.

Illinois Basin

In the Illinois Basin, we own an interest in 1,988 wells. We have approximately 61,000 gross (34,000 net) acres under lease. During the third quarter of 2008, we sold approximately 79,000 net undeveloped acres in Indiana and certain non-producing wells, which was a part of our New Albany Shale exploration projects, for approximately $8.4 million in proceeds.

Total proved reserves in the Illinois Basin increased approximately 26.3 Bcfe, or 74%, to approximately 61.7 Bcfe at December 31, 2009 when compared to year-end 2008, which was primarily a result of the increase in oil prices throughout the year. Annual production decreased 7% from 2008. Capital expenditures in 2009 for developmental drilling and facility improvements in the region were approximately $8.0 million, which funded the drilling of 23 gross (23 net) development wells, of which six were awaiting completion as of December 31, 2009. One exploratory well was also drilled in the region that was determined to be a dry hole. Capital expenditures for drilling and facilities development for the Lawrence Field ASP Flood Project in Lawrence County, Illinois totaled approximately $3.4 million.

At December 31, 2009, the Illinois Basin had a development inventory of 157 proven drilling locations and 131 proven recompletions. Development projects include recompletions, infill drilling and continued refinement of secondary recovery operations. These activities also include increasing reserves and production through aggressive cost control, upgrading lifting equipment, improving gathering systems and surface facilities and performing re-stimulations and re-fracturing operations.

Lawrence Field ASP Flood Project

We are implementing an alkali-surfactant-polymer (“ASP”) flood project in the Cypress and Bridgeport Sandstone reservoirs of our Lawrence Field acreage. The Lawrence Field ASP Flood Project is one of our largest

projects. The Lawrence Field ASP Flood Project is considered an Enhanced Oil Recovery (“EOR”) project, which refers to recovery of oil that is not producible by primary or secondary recovery methods.

The Lawrence Field in Lawrence County, Illinois, is believed to have produced more than 400 million barrels of oil from 23 separate horizons since its discovery in 1906. We currently own and operate 21.2 square miles (approximately 13,500 net acres) of the Lawrence Field, and our properties account for approximately 83% of the current total gross production from the field. The Cypress (Mississippian) and the Bridgeport (Pennsylvanian) sandstones are the major producing horizons in the field. To date, approximately 40% of the estimated one billion barrels of original oil in place has been produced.

In the 1960s, 1970s and 1980s, a number of EOR projects using surfactant polymer floods were implemented in several fields in the Illinois Basin by Marathon Oil Corp. (“Marathon”), Texaco and Exxon in an attempt to recover a portion of the large percentage of the original oil in place that was being bypassed by the secondary recovery waterflood. These test projects reportedly were able to recover incremental oil reserves of 15% to 30% of the original oil in place.

In 1982, Marathon began a surfactant polymer flood project in the Lawrence Field on the Robins Lease, a 25-acre lease in the Lawrence Field within one mile of the site of one of our pilot test locations. This project was initiated at a time when the price per barrel of oil was below $15 and the technology of combining alkali and surfactant with polymer, which significantly reduces costs of recovery compared with the previous surfactant polymer floods, had not yet been fully developed. Despite the high costs of the surfactant polymer flooding employed by Marathon and the low oil prices, the project produced an estimated 450,000 incremental barrels, or an estimated 21% the of original oil in place. While we believe the results of this project are pertinent, there can be no assurance that our Lawrence Field ASP Flood Project, which uses technology that was not developed at the time of the Robins Lease flood, will achieve similar results.

ASP technology, which uses mechanisms to mobilize bypassed residual oil similar to these previous surfactant polymer floods but at significantly lower costs, has been applied by other companies in several fields around the world resulting in significant incremental recoveries of the original oil in place. Chemicals used in the Lawrence Field ASP Flood Project are an alkali (NaOH or Na2CO3), a surfactant and a polymer. The alkali (1% to 2%) and surfactant (0.1% to 0.4%) combination washes residual oil from the reservoir mainly by reducing interfacial tension between the oil and the water. The polymer (800 to 1400 parts per million) is added to improve sweep displacement efficiency. ASP technology achieves its incremental recovery by reducing capillary forces that trap oil, improving aerial and vertical sweep efficiency and reducing mobility ratio.

Our Lawrence Field ASP Flood Project will use ASP technology to flood our Lawrence Field wells. The goal of our Lawrence Field ASP Flood Project is to duplicate the oil recovery performance of the surfactant polymer floods conducted in the field in the 1980s, but at a significantly lower cost. We expect this cost reduction to be accomplished by utilizing newer technologies to optimize the synergistic performance of the three chemicals used, and by using alkali in the formula, which would allow us to use a significantly lower concentration of the more costly surfactant.

In 2000, PennTex Illinois, then known as Plains Illinois, Inc., and the U.S. Department of Energy conducted a study on the potential of an ASP project in the Lawrence Field, with consulting services provided by an independent engineering firm specializing in the design and implementation of chemical oil recovery systems. Based on the modeling of the reservoir characteristics and laboratory tests with cores taken in the Lawrence Field, the evaluation found oil recovery in the field could be increased significantly by installing an ASP flood. Similar EOR techniques have been successfully demonstrated in fields around the world to recover an additional 15% to 30% of the original oil in place. However, there can be no assurance that our Lawrence Field ASP Flood Project will achieve similar results.

In 2006, we engaged a third-party consultant to review and update the evaluation on the application of the ASP process to the Lawrence Field. This evaluation, based on laboratory results, recommended two pilot areas to

evaluate the ASP process in the Bridgeport and Cypress sandstones. The ASP pilot test locations are positioned in areas that we believe are representative of variabilities that can be expected in these reservoirs. Based on our consultant’s recommendations, we drilled and cored the central producing well in each of the two proposed pilot test areas. These cores were sent to our consultant for ASP chemical system design. During 2007, our consultant completed its linear and radial core flood analysis on the Cypress and Bridgeport sandstones, which in the laboratory resulted in an oil recovery rate as high as 21% of the estimated original oil-in-place in the Cypress sandstone, and 24% of the original oil-in-place in the Bridgeport sandstone. These results were in line with our initial projections.

During 2008 and 2009, we completed two four acre pilot tests, one each in the Bridgeport and Cypress sandstones. Both of the pilots demonstrated a response to the chemical injection, as indicated by an increase in both oil production and the oil cut ratio. Each pilot area had individual wells whose oil cut exceeded 10% after the initial response; whereas the oil cuts for both pilots at the time ASP injection was initiated were less than 1%. Our Lawrence Field ASP Project is not a proved project nor are any of the potential reserves associated with this project considered proved at this time.

We have identified, thus far, 27 potential separate flood units (15 Bridgeport/12 Cypress). We are currently in the process of designing the first operationally sized ASP unit in the Bridgeport sandstone which will cover approximately 32 acres with chemical injection commencing during 2010. It is anticipated that the initial response time from the chemical injection date will be approximately four to eight months and the time to peak response will be approximately 10-12 months.

Appalachian Basin

As of December 31, 2009, we own an interest in approximately 587 producing natural gas wells in the Appalachian Basin, located predominantly in Pennsylvania. In addition to our producing wells in the basin, we own 38 proved undeveloped drilling locations with total reserves of 3.5 Bcfe, and three locations with proved developed non-producing reserves totaling 171 MMcf. At December 31, 2009, we had approximately 111,000 gross (63,000 net) acres in the Appalachian Basin under lease, of which 70,000 gross (47,000 net) acres were undeveloped.

Reserves at December 31, 2009 increased 32.8 Bcfe, or 106%, from 2008 due primarily to additional drilling activities, including Marcellus Shale exploration, which were partially offset by a decrease in natural gas prices. Annual production increased 50% over 2008.

Marcellus Shale

The Marcellus Shale is a black, organic rich shale formation located at depths between 5,000 and 8,500 feet and ranges in thickness from 50 to 220 feet on our acreage in southwestern and central Pennsylvania. As of December 31, 2009, we had interests in approximately 90,000 gross (58,000 net) Marcellus Shale prospective acres in these areas of Pennsylvania and we continue to expand our position. The net acreage amount excludes approximately 22,000 acres which can be earned by Williams pursuant to the Participation and Exploration Agreement described below.

On June 18, 2009, we entered into a Participation and Exploration Agreement (the “PEA”) with Williams Production Company, LLC and Williams Production Appalachia, LLC (collectively, “Williams”) that was effective as of May 5, 2009. Under the terms and conditions of the PEA, Williams may acquire, through a “drill-to-earn” structure, 50% of our working interest in certain oil and gas leases covering approximately 44,000 net acres in Centre, Clearfield and Westmoreland Counties, Pennsylvania (the “Project Area”). The PEA effectively provides that, for Williams to earn its 50% interest in the Project Area, Williams will bear 90% of all costs and expenses incurred in the drilling and completion of all wells jointly drilled in the Project Area until such time as Williams has invested approximately $74.0 million (approximately $33.0 million on behalf of us

and $41.0 million for Williams’ 50% share of the wells). Once Williams has completed its carry obligation and acquired 50% of our working interest in the leases within the Project Area, the parties will share all costs of the joint venture operations with an area of mutual interest (including the Project Area) in accordance with their participating interests, which are expected to be on a 50/50 basis. We believe this agreement will allow us to accelerate our activities in the Marcellus Shale while conserving capital at the same time.

During 2009, we met our goal of drilling and completing at least one horizontal well in each of our main project areas. Capital expenditures in 2009 for drilling and facility development totaled $18.2 million, net of approximately $3.1 million that was reimbursed to us upon the execution of the Participation and Exploration Agreement with Williams, which funded the drilling of seven gross (4 net) exploratory wells, of which six gross (3.5 net) were completed and producing and one gross (0.5 net) were awaiting completion and expected to be productive. Our plans for 2010 have allocated approximately $66.0 million in capital expenditures to our Marcellus Shale project areas.

Proved Reserves

In December 2008, the SEC released its finalized rule for “Modernization of Oil and Gas Reporting.” The new rule requires disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to using year-end prices as was practiced previously. The rule also allows for the use of reliable technologies to estimate proved oil and gas reserves, contingent on demonstrated reliability in conclusions about reserve volumes. Under the new rules, companies are required to report on the independence and qualifications of its reserve preparer or auditor, and file reports when a third-party is relied upon to prepare reserve estimates or conduct a reserve audit. The following table sets forth our estimated proved reserves based on the new SEC rules as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K:


Category	Net Reserves
Category	Oil (Barrels)	NGL (Barrels)	Gas (MCF)
Proved Developed	8,526,279	97,151	16,161,494
Proved Undeveloped	1,751,178	1,135,375	40,001,676

Total Proved	10,277,457	1,232,526	56,163,170

All of our reserves are located within the continental United States. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read “Item 1A—Risk Factors—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.” You should also read the notes following the table below and our Consolidated and Combined Financial Statements for the year ended December 31, 2009 in conjunction with the following reserve estimates.

The following table sets forth our estimated proved reserves at the end of each of the past three years:


	2009		2008		2007
Description
Proved Developed Reserves
Oil (Bbls)		8,526,279		5,157,518		9,743,031
Natural Gas (Mcf)		16,161,494		11,695,092		8,089,555
NGLs (Bbls)		97,151		28,974		—
Proved Undeveloped Reserves
Oil (Bbls)		1,751,178		707,757		2,219,154
Natural Gas (Mcf)		40,001,676		18,324,385		4,626,343
NGLs (Bbls)		1,135,375		99,377		—

Total Proved Reserves (Mcfe)(1)(2)(3)		125,223,068		65,981,233		84,489,008

PV-10 Value (millions)(4)	$	190.5	$	84.0	$	183.1
Standardized Measure (millions)	$	144.4	$	68.9	$	236.1

(1)

(2)	Totals of estimated proved reserves, PV-10 Value and Pro Forma Standardized Measure exclude values from our Southwest Region properties which are classified as Held for Sale on our balance sheet at December 31, 2008 and 2007.

(3)	We converted crude oil and NGLs to Mcf equivalent at a ratio of one barrel to six Mcfe.

(4)

Represents the present value, discounted at 10% per annum (PV-10), of estimated future cash flows before income tax of our estimated proved reserves. The estimated future cash flows set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on prevailing economic conditions. The estimated future production is priced based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2009, using $57.65 per bbl and $3.866 per MMBtu and adjusted by lease for transportation fees and regional price differentials. Management believes that the presentation of the non-GAAP financial measure of 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. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flow, please read “Item 6. Selected Historical Financial and Operating Data—Non-GAAP Financial Measures.” Please also read “Item 1A. Risk Factors—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.”

Recent SEC Rule-Making Activity

In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:

•

Commodity Prices: Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.

•

Disclosure of Unproved Reserves: Probable and possible reserves may be disclosed separately on a voluntary basis.

•

Proved Undeveloped Reserve Guidelines: Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

•

Reserves Estimation Using New Technologies: Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

•

Reserves Personnel and Estimation Process: Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

•

Non-Traditional Resources: The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

We adopted the rules effective December 31, 2009, as required by the SEC.

Effect of Adoption.

Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in proved reserves of approximately 125.2 Bcfe. Use of the old year-end prices rules would have resulted in proved reserves of approximately 138.2 Bcfe at December 31, 2009. Therefore, the total impact of the new price methodology rules resulted in negative reserves revisions of 13.0 Bcfe.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2009, our proved undeveloped reserves totaled 1.8 MMBOE of crude oil, 1.1 MMBOE of NGLs and 40.0 Bcf of natural gas, for a total of 57.3 Bcfe. Approximately 81.7% of our PUDs at year-end 2009 were associated with the Appalachian Basin. An additional 18.3% of PUDs at year-end 2009 were associated with the Illinois Basin. All of these projects will have PUDs convert from undeveloped to developed as these projects begin production and/or production facilities are expanded or upgraded. Changes in PUDs that occurred during the year were due to:

•

conversion of approximately 1.1 Bcfe attributable to PUDs into proved developed reserves;

•

positive revisions of approximately 11.2 Bcfe in PUDs due to changes in commodity prices; and

•

24.1Bcfe in PUDs due to extensions and discoveries, which are primarily related to the extension of proved acreage in areas that are prospective for the Marcellus Shale through our drilling activities.

Costs incurred relating to the development of PUDs were approximately $5.8 million in 2009. Estimated future development costs relating to the development of PUDs are projected to be approximately $54.8 million in 2010, $13.3 million in 2011, $4.5 million in 2012, $4.5 million in 2013, and $5.1 million in 2014.

All PUD drilling locations are scheduled to be drilled prior to the end of 2014. Initial production from these PUDs is expected to begin between 2010 to 2015. We do not have PUDs associated with reserves that have been booked for longer than five years.

The following table summarizes the changes in our proved undeveloped reserves for the year ended December 31, 2009:


Proved Undeveloped Reserves (Mcfe)	For the Year Ended December 31, 2009
Beginning proved undeveloped reserves	23,167,189
Undeveloped reserves converted to developed	(1,114,558	)
Revisions	11,200,066
Extensions and discoveries	24,068,297

Ending proved undeveloped reserves	57,320,994

Reservation Estimation.

Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm, evaluated our reserves on a consolidated basis as of December 31, 2009. At December 31, 2009, these consultants collectively reviewed all of our proved reserves. A copy of the summary reserve report is included as Exhibit 99.1 to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserves estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI for our properties such as ownership interest; oil and gas production; well test data; commodity prices and operating and development costs. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as extensive management review and approval.

Acreage and Productive Wells Summary

The following table sets forth, for our continuing operations, our gross and net acreage of developed and undeveloped oil and natural gas leases and our gross and net productive oil and natural gas wells as of December 31, 2009:


	Undeveloped Acreage(1)		Developed Acreage(2)		Total Acreage		Producing Gas Wells			Producing Oil Wells
	Gross	Net	Gross	Net	Gross	Net	Gross		Net	Gross		Net
Appalachian Basin
Pennsylvania(5)	69,082	46,318	42,049	16,707	111,131	63,025	452	(3)	205	—		—
Illinois Basin
Illinois	15,208	5,169	31,781	18,405	46,989	23,574	—		—	1,206	(4)	1,197
Indiana	1,702	808	9,852	9,471	11,554	10,279	—		—	212	(4)	207
Kentucky	1,244	474	821	28	2,065	502	—		—	—		—

Total Illinois Basin	18,154	6,451	42,454	27,904	60,608	34,355	—		—	1,418		1,404

Total	87,236	52,769	84,503	44,611	171,739	97,380	452		205	1,418		1,404

(1)	Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage includes proved reserves.

(2)	Developed acreage is the number of acres allocated or assignable to producing wells or wells capable of production.

(3)	In addition, we own royalty interests in approximately 135 natural gas wells in the Appalachian Basin.

(4)	In addition, we own royalty interests in approximately 111 oil wells in the Illinois Basin.

(5)	The net acreage amount excludes approximately 22,000 acres which can be earned by Williams pursuant to the Participation and Exportation Agreement entered into on June 18, 2009.

Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing lease is renewed or we have obtained production from the acreage subject to the lease before the end of the primary term; in which event, the lease will remain in effect until the cessation of production.

The following table sets forth, for our continuing operations, the gross and net acres of undeveloped land subject to leases summarized in the preceding table that will expire during the periods indicated:


	Expiring Acreage
	Gross	Net
Year Ending December 31,
2010	8,292	7,554
2011	4,116	3,344
2012	12,402	9,116
2013	35,407	18,809
Thereafter	8,865	7,495

Total	69,082	46,318

Drilling Results

The following table summarizes our drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. All of our drilling activities are conducted on a contract basis by independent drilling contractors. We own four workover rigs which are used in our Illinois Basin operations. We do not own any drilling equipment.


	2009				2008				2007
	Gross		Net		Gross		Net		Gross		Net
Development:
Illinois Basin	23.0		23.0		38.0		37.9		32.0		31.8
Appalachian Basin	—		—		18.0		16.2		24.0		13.7
Non-Productive	—		—		—		—		—		—

Total Development wells	23.0		23.0		56.0		54.1		56.0		45.5
Exploratory wells:
Illinois Basin	—		—		—		—		17.0		17.0
Appalachian Basin	7.0		4.0		8.0		7.0		—		—
Non-Productive	1.0		1.0		—		—		—		—

Total Exploratory wells	8.0		5.0		8.0		7.0		17.0		17.0
Total wells	31.0		28.0		64.0		61.1		73.0		62.5

Success ratio(1)	95.8	%	95.3	%	100.0	%	100.0	%	100.0	%	100.0	%

(1)	The success ratio is calculated as follows: (total wells drilled—non-productive wells—wells awaiting completion)/(total wells drilled—wells awaiting completion). As of December 31, 2009, we had seven gross (6.5 net) wells awaiting completion.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often minimal investigation of record title is made at the time of lease acquisition. A more comprehensive mineral title opinion review, a topographic evaluation and infrastructure investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

•

customary royalty interests;

•

liens incident to operating agreements and for current taxes;

•

obligations or duties under applicable laws;

•

development obligations under oil and gas leases;

•

net profit interests;

•

overriding royalty interests;

•

non-surface occupancy leases; and

•

lessor consents to placement of wells.

ITEM 3.

LEGAL PROCEEDINGS

The information set forth in Note 21, “Litigation,” in the notes to our Consolidated and Combined Financial Statements included in Item 8 of Part II of this report is incorporated herein by reference.

ITEM 4.

RESERVED

PART II

ITEM 5.

MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

We completed the initial public offering of our common stock in July 2007. Since that time, our common stock has been quoted on the NASDAQ Global Market under the symbol “REXX”. Before then, there was no public market for our common stock. As of March 2, 2010, there were approximately 56 holders of record of our common stock.

The following table sets forth, for the periods indicated, the range of the daily high and low sale prices for our common stock as reported by NASDAQ.


2009	High		Low
First quarter	$	4.37	$	0.99
Second quarter		7.66		2.49
Third quarter		8.58		4.02
Fourth quarter		13.48		7.38

2008	High		Low
First quarter	$	17.95	$	9.50
Second quarter		29.92		16.09
Third quarter		27.15		13.79
Fourth quarter		15.58		2.36

The closing price of our common stock at March 2, 2010 was $14.54.

Dividends

We have not paid cash dividends on our common stock since our inception in March 2007. We do not anticipate paying any dividends on the shares of our common stock in the foreseeable future. We currently intend to reinvest our earnings to finance the expansion of our business. In addition, the terms of our senior credit facility generally prohibit the payment of cash dividends to holders of our common stock.

Issuer Purchases of Equity Securities

We do not have a stock repurchase program for our common stock.

Performance Graph

The following graph presents a comparison of the yearly percentage change in the cumulative total return on our common stock over the period from July 25, 2007, the date our common stock was first publicly traded, to December 31, 2009, with the cumulative total return of the S&P 500 index and the Dow Jones U.S. Oil and Gas Exploration and Production Index over the same period. The graph assumes that $100 was invested on July 25, 2007 in our common stock at the closing market price at the beginning of this period and in each of the other two indices, and the reinvestment of all dividends, if any. This historic stock price performance is not necessarily indicative of future stock performance.

LOGO


	S&P		DJ U.S. E&P Index		Rex Energy
July 25, 2007	$	100	$	100	$	100
December 31, 2007	$	97	$	117	$	118
December 31, 2008	$	60	$	69	$	29
December 31, 2009	$	73	$	97	$	118

The performance graph and the information contained in this section is not “soliciting material,” is being “furnished,” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof, and irrespective of any general incorporation language contained in such filing.

ITEM 6.

SELECTED FINANCIAL DATA

Summary Financial Data

The following table shows selected consolidated and combined financial data of Rex Energy Corporation and the Predecessor Companies for each of the periods indicated. The historical consolidated financial data has been prepared for Rex Energy Corporation for the years ended December 31, 2009 and 2008. The historical combined financial data has been prepared for the Predecessor Companies for the years ended December 31, 2007, 2006, and 2005. The historical consolidated and combined financial statements for all years presented are derived from the historical audited financial data of Rex Energy Corporation and the Predecessor Companies. All material intercompany balances and transactions have been eliminated. Because each of the Predecessor Companies was taxed as a partnership for each of the periods indicated for federal and state income tax purposes, the following statements make no provision for income taxes for the years ended December 31, 2006, 2005 and the seven month period ended July 31, 2007. Provision for income tax is presented for the five month period ended December 31, 2007. This information should be read in conjunction with Item 7 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated and combined financial statements and related notes as of December 31, 2009, 2008 and 2007 and for each of the years ended December 31, 2009, 2008 and 2007, included elsewhere in this report. These selected combined historical financial results may not be indicative of our future financial or operating results.

The following tables include the non-GAAP financial measure of EBITDAX. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures” below.


	Rex Energy Corporation Consolidated			Rex Energy Corporation Consolidated			Rex Energy Corporation Consolidated & Combined Predecessor Companies			Rex Energy Corporation Consolidated & Combined Predecessor Companies			Rex Energy Corporation Consolidated & Combined Predecessor Companies
	Year Ended December 31, ($ in Thousands, Except Per Share Data)
	2009			2008			2007			2006			2005
Statement of operations data:
Operating Revenue:
Oil and Natural Gas Sales	$	48,534		$	84,013		$	58,133		$	38,800		$	27,743
Other Revenue		157			123			101			124			270

Total Operating Revenue		48,691			84,136			58,234			38,924			28,013

Operating Expenses:
Production and Lease Operating Expense		22,157			26,511			22,361			14,084			10,944
General and Administrative		15,858			15,185			7,793			5,594			3,088
Impairment Expense		1,625			71,349			—			—			—
(Gain) Loss on Disposal of Assets		427			6,468			(12	)		(91	)		(1,016	)
Exploration Expense		2,080			3,261			1,238			—			107
Depletion, Depreciation, Amortization and Accretion		25,205			37,904			17,804			8,871			3,032

Total Operating Expenses		67,352			160,678			49,184			28,458			16,155

Income (Loss) from Operations		(18,661	)		(76,542	)		9,050			10,466			11,858

Other Income (Expense):
Interest Income		7			328			15			94			444
Interest Expense		(833	)		(1,091	)		(5,665	)		(6,110	)		(1,697	)
Gain (Loss) on Derivatives, net		(7,913	)		27,328			(32,429	)		607			(13,471	)
Other Income (Expense)		(170	)		(168	)		(18	)		(132	)		216

Total Other Income (Expense)		(8,909	)		26,397			(38,097	)		(5,541	)		(14,508	)

Income (Loss) from Continuing Operations Before Income Taxes		(27,570	)		(50,145	)		(29,047	)		4,925			(2,650	)
Income Tax Benefit		11,002			9,167			7,365			—			—

Income (Loss) From Continuing Operations		(16,568	)		(40,978	)		(21,682	)		4,925			(2,650	)
Income (Loss) from Discontinued Operations, Net of Income Taxes		323			(7,704	)		(681	)		1,022			9

Net Income (Loss)		(16,245	)		(48,682	)		(22,363	)		5,947			(2,641	)
(Income) Loss Attributable to Noncontrolling Interests		12			—			6,152			(2,133	)		(2,304	)

Net Income (Loss) Attributable to Rex Energy	$	(16,233	)	$	(48,682	)	$	(16,211	)	$	3,814		$	(4,945	)

Earnings per common Share(1):
Basic and Diluted-loss from continuing operations attributed to Rex common stockholders	$	(0.45	)	$	(1.18	)	$	(0.37	)	$	—		$	—
Basic and Diluted-income (loss) from discontinued operations attributed to Rex common stockholders		0.01			(0.22	)		0.02			—			—

Basic and Diluted-net loss attributed to Rex common stockholders	$	(0.44	)	$	(1.40	)	$	(0.35	)	$	—		$	—

Basic and Diluted-weighted average shares of common stock outstanding		36,806			34,595			30,795			—			—

(1)	Earnings per common share for 2007 represents a loss from continuing operations of $11,304 and a gain from discontinued operations of $664 for the 5 month period ended December 31, 2007.


	Year Ended December 31, ($ in Thousands)
	2009			2008			2007			2006			2005
Other Financial Data:
EBITDAX from Continuing Operations	$	22,489		$	29,095		$	28,227		$	12,545		$	3,963
Cash Flow Data:
Cash provided by operating activities		20,774			32,428			17,555			12,920			9,527
Cash used by investing activities		(30,061	)		(127,800	)		(40,102	)		(94,446	)		(19,404	)
Cash provided by financing activities		7,823			101,333			23,032			79,438			9,772
Balance Sheet Data:
Cash and cash equivalents		5,582			7,046			1,085			600			3,188
Property and Equipment (net of accumulated depreciation)		275,261			249,858			191,171			117,309			34,523
Total Assets		304,950			302,006			268,264			144,611			55,291
Current Liabilities, including current portion of long-term debt		32,411			17,353			20,612			53,684			32,297
Long-Term Debt, net of current maturities		23,049			15,000			27,207			45,442			3,360
Total Liabilities		84,753			70,158			103,827			108,639			42,080
Noncontrolling Interests		3,343			—			—			36,589			24,130
Owners’ Equity		220,197			231,848			164,437			(617	)		(10,920	)

Summary Operating and Reserve Data

The following table summarizes our operating and reserve data as of and for each of the periods indicated for continuing operations. The table includes the non-GAAP financial measure of PV-10. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flow, its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures” below.


	Year Ended December 31, ($ in Thousands)
	2009			2008			2007
Production
Oil (Bbls)		720,010			776,185			769,911
Natural gas (Mcf)		1,510,500			1,036,891			786,095
NGLs (Bbls)		7,750			—			—
Mcf equivalent (Mcfe)		5,877,060			5,694,001			5,405,561
Oil and natural gas sales(1)
Oil sales	$	41,881		$	74,230		$	52,408
Natural gas sales		6,460			9,783			5,725
NGLs sales		193			—			—
Total	$	48,534		$	84,013		$	58,133
Average sales price(1)
Oil ($ per Bbl)	$	58.17		$	95.63		$	68.07
Natural gas ($ per Mcf)	$	4.28		$	9.43		$	7.28
NGLs ($ per Bbl)	$	24.90		$	—		$	—
Mcf equivalent ($ per Mcfe)	$	8.26		$	14.75		$	10.75
Average production cost
Mcf equivalent ($ per Mcfe)	$	3.77		$	4.66		$	4.14
Estimated proved reserves(2)
Bcf equivalent (Bcfe)		125.2			66.0			84.6
% Oil		49	%		53	%		85	%
% Proved producing		51	%		65	%		72	%
PV-10 (millions)	$	190.5		$	84.0		$	362.4
Pro forma standardized measure (millions)(3)	$	144.4		$	68.9		$	236.1

(1)	The December 31, 2007, 2008 and 2009 information excludes the impact of our financial derivative activities.

(2)

The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our financial derivative activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The estimated present value of proved reserves does not give effect to indirect expenses such as debt service and future income tax expense, asset retirement obligations, or to depletion, depreciation and amortization. The reserve information shown is estimated. The certainty of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation, and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

(3)	Because each of the Predecessor Companies was a flow-through entity for state and federal tax purposes, our historical standardized measure does not deduct state or federal taxes. This differs from our pro forma standardized measure, which deducts state and federal taxes.

Non-GAAP Financial Measures

We include in this report our calculations of EBITDAX and PV-10, which are non-GAAP financial measures. Below, we provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measure as calculated and presented in accordance with GAAP.

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, depreciation, depletion, amortization, unrealized losses from financial derivatives, 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 our 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) in measuring our performance, nor used as an exclusive measure of cash flow, 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 statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and we believe 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 our 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 EBITDAX assists our lenders and investors in comparing a company’s 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 and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Additionally, 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.

The following table presents a reconciliation of our net income to our EBITDAX for each of the periods presented ($ in thousands):


	Year Ended December 31,
	2009			2008			2007			2006			2005
Net Income (Loss)	$	(16,568	)	$	(40,978	)	$	(21,682	)	$	4,925		$	(2,650	)
Add Back Depletion, Depreciation, Amortization and Accretion		25,205			37,904			17,804			8,871			3,032
Add Back Non-Cash Compensation Expense		1,557			2,990			211			—			—
Add Back Interest Expense(1)		1,602			1,342			5,646			6,110			1,697
Add Back Exploration & Impairment Expense		3,705			74,610			1,238			—			107
Less Interest Income		(7	)		(328	)		(15	)		(94	)		(444	)
Add Back (Gain) Loss on Disposal of Assets		427			6,468			(12	)		(91	)		(1,016	)
Add Back Unrealized (Gain) Loss on Financial Derivatives		17,558			(43,746	)		26,250			(5,043	)		5,541
Add Back Noncontrolling Interest Share of Net Gain (Loss)		12			—			6,152			(2,133	)		(2,304	)
Less Income Tax Benefit		(11,002	)		(9,167	)		(7,365	)		—			—

EBITDAX from Continuing Operations		22,489			29,095			28,227			12,545			3,963
Add EBITDAX from Discontinued Operations		53			3,652			3,021			3,374			297

EBITDAX	$	22,542		$	32,747		$	31,248		$	15,919		$	4,260

(1)	Includes realized settlements on interest rate swap.

PV-10

The following table shows the reconciliation of PV-10 to our pro forma standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 represents our estimate of the present value, discounted at 10% per annum, of estimated future cash flows before income tax of our estimated proved reserves. Our estimated future cash flows as of December 31, 2007, 2008 and 2009 were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on the prevailing economic conditions. The estimated future production is priced at December 31, 2007 and 2008, without escalation, using $92.50 and $41.00 per Bbl of oil, respectively, and $6.795 and $5.71 per MMBtu of natural gas, respectively, as adjusted by lease for transportation fees and regional price differentials. The estimated future production for the year ended December 31, 2009, was priced based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2009, without escalation, using $57.65 per Bbl of oil and $3.866 per MMBtu of natural gas, as adjusted by lease for transportation fees and regional price differentials. 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.


	2009		2008		2007
Reconciliation of PV-10 to Pro forma standardized measure (millions)(a)
Pro forma standardized measure of discounted future net cash flows	$	144.4	$	68.9	$	236.1
Add: Present value of future income tax discounted at 10%(b)		30.0		—		120.8
Add: Present value of future asset retirement obligations discounted at 10%		16.1		15.1		5.5
PV-10	$	190.5	$	84.0	$	362.4

(a)	Does not include values of our Southwest Region properties which are classified as Assets Held for Sale on our balance sheet.

(b)

At December 31, 2008, the tax basis of our assets exceeded the future cash flows of our oil and gas properties, which indicates that no future income taxes will be paid. Impairment testing was performed on our oil and gas properties at year end based on escalating future oil and natural gas prices. The standardized measure of discounted future net cash flows at December 31, 2008 was based on the year end SEC commodity prices, which are held constant for the life of the properties.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with “Item 6. Selected Financial Data” and the Consolidated and Combined Financial Statements and related notes included elsewhere in this report. This discussion contains forward-looking statements reflecting our current expectations and estimates, and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” appearing elsewhere in this report. All financial and operating data presented are the results of continuing operations unless otherwise noted.

Overview of Our Business

We are headquartered in State College, Pennsylvania, and have a regional office in Bridgeport, Illinois.

Our financial results depend upon many factors, particularly the price of oil and gas. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, refinery or pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success.

On March 24, 2009, we completed the sale of certain oil and gas leases, wells and related assets predominantly located in the Permian Basin in the states of Texas and New Mexico. We received net cash proceeds of approximately $17.3 million. We have reclassified these assets and associated liabilities as “held for sale” on our Consolidated Balance Sheets and have reported the results of operations under discontinued operations on our Consolidated and Combined Statements of Operations. Total revenues for these properties for the years ended December 31, 2007, 2008 and 2009 were $5.7 million, $6.4 million and $0.2 million, respectively. Total assets held for sale for the years ended December 31, 2009 and 2008 were $0 and $18.9 million, respectively.

Source of Our Revenues

We generate our revenue primarily from the sale of crude oil to refining companies and natural gas to local distribution and pipeline companies. Our operating revenue before the effects of financial derivatives from these operations, and their relative percentages of our total revenue, consisted of the following ($ in thousands):


	2009		% of Total		2008		% of Total		2007		% of Total
Revenue from Oil Sales	$	41,881	86.0	%	$	74,230	88.3	%	$	52,408	90.0	%
Revenue from Natural Gas Sales		6,460	13.3	%		9,783	11.6	%		5,725	9.8	%
Revenue from NGL Sales		193	0.4	%		—	0.0	%		—	0.0	%
Other		157	0.3	%		123	0.1	%		101	0.2	%

Total	$	48,691	100.0	%	$	84,136	100.0	%	$	58,234	100.0	%

We have identified the impact of generally volatile commodity prices in the last several years as an important trend that we expect to affect our business in the future. If commodity prices increase, we would expect not only an increase in revenue, but also the competitive environment for quality drilling prospects, qualified geological and technical personnel and oil field services, including rig availability. Increasing competition in these areas would likely result in higher costs in these areas, and could result in unavailability of drilling rigs, thus affecting the profitability of our future operations. We may not be able to compete successfully in the future with larger competitors in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. In the event of a declining commodity price environment, our revenues would decrease and we would anticipate that the cost of materials and services would decrease as well, although at a slower rate. Decreasing oil or natural gas prices may also make some of our prospects uneconomical to drill.

Principal Components of Our Cost Structure

Our operating and other expenses consist of the following:

•

Production and Lease Operating Expenses. Day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include workovers, repairs to our oil and gas properties not covered by insurance, and various production taxes that are paid based upon rates set by federal, state, and local taxing authorities.

•

Exploration Expense. Geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory wells, also known as dry holes.

•

General and Administrative Expense. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees, and legal compliance are included in general and administrative expense. General and administrative expense includes non-cash stock-based compensation expense as part of employee compensation.

•

Interest. We typically finance a portion of our working capital requirements and acquisitions with borrowings under our senior credit facility. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We may continue to incur significant interest expense as we continue to grow.

•

Depreciation, Depletion, Amortization and Accretion. The systematic expensing of the capital costs incurred to acquire, explore and develop natural gas and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities.

•

Income Taxes. We are subject to state and federal income taxes but are currently not in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). We do pay some state income taxes where our IDC deductions do not exceed our taxable income or where state income taxes are determined on another basis. Currently, all of our federal taxes are deferred; however, at some point, we believe we will use all of our net operating loss carryforwards and we believe we will recognize current income tax expense and continue to recognize current tax expense as long as we are generating taxable income.

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include EBITDAX, lease operating expenses per Mcf equivalent (“Mcfe”), growth in our proved reserve base, and general and administrative expenses per Mcfe. The following table presents these metrics for continuing operations for each of the three years ended December 31, 2009, 2008 and 2007.


	Performance Measurements
	Years Ended December 31,
	2009		2008		2007
EBITDAX ($ in Thousands)	$	22,489	$	29,095	$	28,227
Production Cost per Mcfe	$	3.77	$	4.66	$	4.14
Total Proved Reserves (Bcfe)		125.2		66.0		84.5
G&A per Mcfe	$	2.70	$	2.67	$	1.44

EBITDAX

•

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.

Production Cost per Mcfe

Production costs are comprised of those expenses which are directly attributable to our producing oil and gas leases, including state and county production taxes, production related insurance, the cost of materials, maintenance, electricity, chemicals, fuel and the wages of our field personnel. Our production costs per BOE are higher than those of many of our peers primarily because of the nature of our oil properties, many of which are mature waterflood properties. Our production cost per Mcfe produced in 2009 was $3.77 as compared to $4.66 in 2008 and $4.14 in 2007. As we continue to develop our non-proved properties, such as the Marcellus Shale, we believe this metric will continue to decrease on a per unit basis.

Growth in our Proved Reserve Base

We measure our ability to grow our proved reserves over the amount of our total annual production. As we produce oil and gas attributable to our proved reserves, our proved reserves decrease each year by that amount of production. We attempt to replace these produced proved reserves each year through the addition of new proved reserves through our drilling and other property improvement projects and through acquisitions. Our proved reserves have fluctuated since 2007, from 84.6 Bcfe at year end 2007 to 66.0 Bcfe at year end 2008 to 125.2 Bcfe

at year end 2009. Our reserve replacement ratio for year end 2007 was approximately 47% based on total production for the year of 5.4 Bcfe, purchases of reserves of 0.5 Bcfe, and extensions, discoveries and other additions of 2.1 Bcfe. Our reserve replacement ratio for year end 2008 was approximately 328% based on total production for the year of 5.7 Bcfe, purchases of reserves of 1.0 Bcfe, and extensions, discoveries and other additions of 17.7 Bcfe. Our reserve replacement ratio for year end 2009 was approximately 410% based on total production for the year of 5.9 Bcfe, and extensions, discoveries and other additions of 21.0 Bcfe.

Our proved reserve base increased in 2009 when compared to 2008 predominately due to the increase in oil prices used for the reserves determination and our successful drilling programs in the Marcellus Shale. These gains were partially offset by a decrease in natural gas prices used for the reserves determination. The change in oil prices primarily impacted our Illinois Basin, which accounts for 73.5% of our total production, and 100% of our oil production. Additionally, our proved reserve base in the Appalachian Basin increased by approximately 106%, despite a decrease in natural gas prices.

General and Administrative Expenses as a Percentage of Oil and Gas Revenue

Our general and administrative expenses include fees for well operating services, marketing, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our general and administrative expenses in relation to our revenue because these expenses have a direct impact on our profitability. In 2009 our general and administrative expenses per Mcfe produced increased to $2.70 from $2.67 in 2008 and from $1.44 in 2007.

Results of Continuing Operations

General Overview

Operating revenue decreased 42.1% for 2009 over 2008. This decrease is primarily due to lower average sales prices per Mcfe throughout the year and a decrease in oil production, partially offset by increased gas production. For 2009, total production increased 3.2% to 5,877 MMcfe from 5,694 MMcfe in 2008 due to the continued success of our drilling programs, primarily in the Marcellus Shale.

Operating expenses decreased $93.3 million in 2009, or 58.1%, as compared to 2008. Operating expenses are primarily composed of production expenses, general and administrative expenses, gain (loss) on disposal of assets, exploration expenses, impairment of oil and gas properties and depreciation, depletion, amortization and accretion expenses (“DD&A”). These decreases were primarily due to non-cash impairment expenses of $71.3 million incurred during 2008 compared to non-cash impairment expenses of $1.6 million incurred during 2009. The impairment expense incurred during 2008 was primarily attributable to the decline in oil and gas prices during the year, at which time we determined that the carrying value of some of our oil and gas properties was not recoverable and exceeded their fair value. Also contributing to the decrease were lower DD&A expenses, which decreased approximately $12.7 million when compared to 2008, primarily due to our increased proved reserves which decelerated our units-of-production calculation. Other contributing factors included a decrease in losses on the disposal of assets of approximately $6.0 million, which was impacted by the sale of our New Albany Shale assets in 2008, as well as a decrease in our lease operating expenses of approximately $4.4 million, which was attributable to lower activity levels in our Illinois Basin operations and increased cost management efforts.

Comparison of the Year Ended December 31, 2009 to the Year Ended December 31, 2008

Oil and gas revenue for the years ended December 31, 2009 and 2008 ($ in thousands except price per Mcfe) is summarized in the following table:


	December 31,
	2009		2008			Change			%
Oil and Gas Revenues:
Oil sales revenue	$	41,881	$	74,230		$	(32,349	)	(43.6	)
Oil derivatives realized(1)		2,626		(15,613	)		18,239		116.8

Total oil revenue and derivatives realized	$	44,507	$	58,617		$	(14,110	)	(24.1	)

Gas sales revenue	$	6,460	$	9,783		$	(3,323	)	(34.0	)
Gas derivatives realized		3,216		(554	)		3,770		680.5

Total gas revenue and derivatives realized	$	9,676	$	9,229		$	447		4.8
Total NGL revenue	$	193	$	—		$	193		100.0

Consolidated sales	$	48,534	$	84,013		$	(35,479	)	(42.2	)
Consolidated derivatives realized		5,842		(16,167	)		22,009		136.1

Total oil & gas revenue and derivatives realized	$	54,376	$	67,846		$	(13,470	)	(19.9	)

Total Mcfe Production		5,877,060		5,694,001			183,059		3.2
Average Realized Price per Mcfe, including the effects of derivatives	$	9.25	$	11.92		$	(2.67	)	(22.4	)

(1)	2009 oil derivatives realized excludes approximately $4.6 million in proceeds that were received upon the early settlement of oil hedges relating to the 2011 calendar year.

Average realized price received for oil and gas during 2009 was $9.25 per Mcfe, a decrease of 22.4%, or $2.67 per Mcfe, from the prior year. The average realized price for oil, including the effects of derivatives, in 2009 decreased 18.1% or $13.70 per barrel, whereas the average realized price for natural gas, including the effects of derivatives, decreased 28.0%, or $2.49 per Mcf, from 2008. Our derivative activities effectively increased net realized prices by $0.99 per Mcfe in 2009 and decreased net realized prices by $2.84 per Mcfe in 2008.

Production volume increased 3.2% from 2008 primarily due to the success of our Marcellus Shale horizontal drilling plan in the Appalachian Basin where production increased approximately 50.4%, or 523 MMcfe. Our production for 2009 averaged approximately 16,102 Mcfe per day of which 73.5% was attributable to the Illinois Basin and 26.5% to the Appalachian Basin.

Other operating revenue for 2009 of approximately $157,000 increased $34,000, or 27.6%, from 2008. We generate other operating revenue from various activities such as revenue from the transportation of natural gas and well tending.

Production and lease operating expense decreased approximately $4.4 million, or 16.4%, in 2009 from 2008. The decrease in expense can be partially attributed to lower activity levels in our Illinois Basin operations throughout 2009. We also implemented several cost reduction measures in an effort to mitigate discretionary spending and to lower overall operating expenses.

General and administrative expense of approximately $15.9 million for 2009 increased approximately $0.7 million, or 4.4%, from 2008. The year-over-year increase is primarily attributable to legal expenses, which have increased due to accruals associated with the pending actions related to our Marcellus Shale leasing activities as well as the accruals associated with a Settlement Agreement and Release entered into in December of 2009 to settle a class action lawsuit (See Note 21,“Litigation,” to our Consolidated and Combined Financial Statements).

Impairment expense decreased to $1.6 million in 2009 from $71.3 million in 2008. We evaluate impairment of our properties when events occur that indicate that the carrying value of these properties may not be recoverable. During 2008, we determined that, due to the decrease in oil and natural gas prices, the carrying value of some of our properties was not recoverable and exceeded their fair value. During 2009, the recoverability of our properties improved as oil prices increased and we continued to drill successful horizontal wells in areas where the Marcellus Shale is prospective. We did, however, identify certain geographic regions that are outside the scope of our current plans, which has increased the probability of future lease expirations. The capitalized costs associated with these properties are periodically evaluated as to their recoverability based on changes brought about by economic factors and potential shifts in our business strategy. As economic and strategic conditions change and we continue to develop unproved properties, our estimates of impairment will likely change and we may increase or decrease expense.

Loss on disposal of assets for 2009 was approximately $0.4 million as compared to $6.5 million for 2008. We, from time to time, sell or otherwise dispose of certain fixed assets and wells that are no longer effectively used by us, and a gain or loss may be recognized when such an asset is sold. The loss incurred in 2008 is primarily due to the sale of our New Albany Shale acreage holdings in areas of the Illinois Basin.

Exploration expense of oil and gas properties for 2009 decreased approximately $1.2 million from $3.3 million in 2008. During 2008, we incurred higher expenses due to geological modeling in our Lawrence Field ASP Project and geophysical evaluation and modeling associated with our Marcellus Shale activities during the year. Our expense associated with geophysical evaluation and modeling associated with our Marcellus Shale activities decreased in 2009, in part, due to our joint venture with Williams as we share the cost of these activities on an equal basis.

Depletion, depreciation, amortization and accretion expense of approximately $25.2 million for 2009 decreased approximately $12.7 million, or 33.5%, from 2008. This decrease can be primarily explained by the upward revision in the estimated lives of our proved reserves. We calculate our depletion on a units-of-production basis, which decelerated in relation to our higher proved reserves base.

Interest expense, net of interest income, for 2009 was approximately $826,000 as compared to $763,000 for 2008. The slight increase in interest expense, net of interest income, was primarily due to the decrease in the amount of cash on hand, for which we receive interest income, as well as depressed interest rates when compared to the prior year.

Gain (loss) on derivatives, net for 2009 was a loss of approximately $7.9 million as compared to a gain of $27.3 million for 2008. This change is attributed to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the time we entered into a derivative contract, while gains would suggest the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

Other expense increased by $2,000 to approximately $170,000 in 2009. Our other expense is characterized by the recognition of gains or losses on the sale of scrap inventory and physical yard inventory adjustments and fluctuates from period to period.

Net loss attributable to Rex Energy for 2009 was approximately $16.2 million, as compared to a net loss of approximately $48.7 million for 2008 as a result of the factors discussed above.

Comparison of the Year Ended December 31, 2008 to the Year Ended December 31, 2007

Oil and gas revenue for the years ended December 31, 2008 and 2007 ($ in thousands except price per Mcfe) is summarized in the following table:


	December 31,
	2008			2007			Change			%
Oil and Gas Revenues:
Oil sales revenue	$	74,230		$	52,408		$	21,822		41.6
Oil derivatives realized		(15,613	)		(6,828	)		(8,785	)	(128.7	)

Total oil revenue and derivatives realized	$	58,617		$	45,580		$	13,037		28.6

Gas sales revenue	$	9,783		$	5,725		$	4,058		70.9
Gas derivatives realized		(554	)		630			(1,184	)	(187.9	)

Total gas revenue and derivatives realized	$	9,229		$	6,355		$	2,874		45.2

Consolidated sales	$	84,013		$	58,133		$	25,880		44.5
Consolidated derivatives realized		(16,167	)		(6,198	)		(9,969	)	(160.8	)

Total oil & gas revenue and derivatives realized	$	67,846		$	51,935		$	15,911		30.6

Total Mcfe Production		5,694,001			5,405,561			288,440		5.3
Average Realized Price per Mcfe, including the effects of derivatives	$	11.92		$	9.61		$	2.31		24.0

Average realized price received for oil and gas during 2008 was $11.92 per Mcfe, an increase of 24.0%, or $2.31 per Mcfe, from the prior year. The average realized price for oil in 2008 increased 27.6% or $16.34 per barrel, whereas the average realized price for natural gas increased 10.1%, or $0.82 per Mcf, from 2007. Our derivative activities effectively decreased net realized prices by $2.84 per Mcfe in 2008 and $1.15 per Mcfe in 2007.

Production volume increased 5.3% from 2007 primarily due to continued success with our oil and gas well drilling activities, particularly in the Appalachian Basin where production increased approximately 31.9%, or 251 MMcfe. Our production for 2008 averaged approximately 15,600 Mcfe per day of which 81.8% was attributable to the Illinois Basin and 18.2% to the Appalachian Basin.

Other operating revenue for 2008 of approximately $123,000 increased $22,000, or 21.8%, from 2007. We generate other operating revenue from various activities such as revenue from the transportation of natural gas and well tending.

Production and lease operating expense increased approximately $4.2 million, or 18.6%, in 2008 from 2007. The increase in expense can be partially attributed to a higher cost of conducting business in the oil and natural gas industry, as the cost of durable goods has risen throughout our areas of operation for items such as steel, chemicals and electricity. Also contributing to the increase in expense is the greater number of wells in service in 2008 as compared to 2007.

General and administrative expense of approximately $15.2 million for 2008 increased approximately $7.4 million, or 94.9%, from 2007. The increase in G&A expense was primarily due to increased costs associated with consulting fees related to compliance with the Sarbanes-Oxley Act of 2002 and additional staffing needs in our corporate headquarters and field offices in relation to our growth. Non-cash compensation expenses increased from 2007 by approximately $2.8 million to $3.0 million in 2008, of which approximately $1.1 million is due to the voluntary cancellation of 100,000 stock option awards by members of our board of directors.

Impairment expense increased to $71.3 million in 2008 from $0 in 2007. We evaluate impairment of our properties when events occur that indicate that the carrying value of these properties may not be recoverable. At

December 31, 2008, we determined that the carrying value of some of our oil and gas properties was not recoverable and exceeded fair value. The decrease in our assets’ fair value was the result of the decrease in oil and natural gas prices at year end as compared to 2007. Contributing to the increase in impairment expense was the impairment of goodwill of approximately $32.7 million.

Loss on disposal of assets for 2008 was approximately $6.5 million as compared to a gain of $12,000 for 2007. We, from time to time, sell or otherwise dispose of certain fixed assets and wells that are no longer effectively used by us, and a gain or loss may be recognized when such an asset is sold. The loss incurred in 2008 is primarily due to the sale of our New Albany Shale acreage holdings in areas of the Illinois Basin.

Exploration expense of oil and gas properties for 2008 increased approximately $2.0 million from $1.2 million in 2007. This increase is primarily due to geological modeling in our Lawrence Field ASP Project and geophysical evaluation and modeling associated with our Marcellus Shale activities during the year.

Depletion, depreciation, amortization and accretion expense of approximately $37.9 million for 2008 increased approximately $20.1 million, or 113%, from 2007. This increase can be primarily explained by the downward revision in the estimated lives of our proved reserves. We calculate our depletion on a units-of-production basis, which accelerated in relation to our lower proved reserves base.

Interest expense, net of interest income, for 2008 was approximately $763,000 as compared to $5.6 million for 2007. The decrease of $4.6 million is primarily due to the decrease in the average balance on our long-term debt, lines of credit and other loans and notes payable. We used the proceeds of our public offering in the second quarter of 2008 to pay off our entire line of credit balance in May 2008. As a result, we did not have any amounts drawn on our line of credit until October 2008.

Gain (loss) on derivatives, net for 2008 was approximately $27.3 million as compared to a loss of $32.4 million for 2007. This change is attributed to the volatility of oil and gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Unrealized losses from derivative activities generally reflect higher oil and gas prices in the marketplace than were in effect at the time we entered into a derivative contract, while unrealized gains would suggest the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

Other expense increased by $150,000 to approximately $168,000 in 2008. The change is primarily due to the recognition of gains and losses on the sale of scrap inventory.

Net loss attributable to Rex Energy for 2008 was approximately $48.7 million, as compared to a net loss of approximately $16.2 million for 2007 as a result of the factors discussed above.

Capital Resources and Liquidity

Our primary financial resource is our base of oil and gas reserves. We grant security interests in our producing oil and gas properties to a group of banks to secure our senior credit facility. The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties. We borrow funds on our senior credit facility as needed to supplement our operating cash flow and as a financing source for our capital expenditure program. Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of product prices on cash flow can be mitigated through the use of commodity derivatives. If we are unable to replace our oil and gas reserves through our acquisitions, development or exploration programs, we may also suffer a reduction in our operating cash flow and access to funds under the senior credit facilities. Under extreme

circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

Our cash flow from operations is driven by commodity prices and production volumes. Prices for oil and gas are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from heightened demand for hydrocarbons from emerging nations. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Cash flows from operations have been primarily used to fund exploration and development of our oil and gas interests.

Financial Condition and Cash Flows for the Years Ended December 31, 2009, 2008 and 2007

The following table summarizes our sources and uses of funds for the periods noted:


	For The Years Ended December 31, ($ in Thousands)
	2009			2008			2007
Cash flows provided by operating activities	$	20,774		$	32,428		$	17,555
Cash flows used in investing activities		(30,061	)		(127,800	)		(40,102	)
Cash flows provided by financing activities		7,823			101,333			23,032

Net increase (decrease) in cash and cash equivalents	$	(1,464	)	$	5,961		$	485

Net cash provided by operating activities decreased by approximately $11.7 million in 2009 when compared to 2008, to $20.8 million. In 2009, cash flows decreased primarily due to decreases in the average price received for our oil and natural gas production. We partially offset these declines in prices by focusing on cost control measures by decreasing discretionary activities in our Illinois Basin and implementing cost reduction plans which helped to lower our overall production and lease operating expenses. Additionally, our realized gains on derivatives during 2009 helped to offset the lower commodity prices by approximately $10.4 million.

Net cash used in investing activities decreased by approximately $97.7 million in 2009 when compared to 2008, to $30.1 million. During 2009, we took a conservative approach to our investing activities, whereby we decreased our normal development activities and put more focus on our more strategic projects, such as Marcellus Shale exploration. Also contributing to the decreased investing activity was the Participation and Exploration agreement entered into with Williams. Throughout the course of the second half of 2009, Williams has been responsible for 90% of the drilling and completion costs of our Marcellus Shale wells within our area of joint operations. In addition, upon the signing of the Participation and Exploration agreement, Williams reimbursed us for costs previously incurred in the amount of $3.1 million.

Net cash provided by financing activities decreased by approximately $93.5 million in 2009 when compared to 2008, to $7.8 million. During 2008, we received net proceeds from the issuance of common stock of approximately $113.0 million. Our cash provided by financing activities in 2009 include net proceeds from long-term borrowings of approximately $7.8 million.

Capital Requirements

Our primary needs for cash are for exploration, development and acquisition of oil and gas properties and repayment of principal and interest on outstanding debt. During 2009, $50.9 million of capital was expended on drilling projects, facilities and related equipment and acquisitions to purchase additional interests in producing properties and unproved acreage. The capital program was funded by net cash flows from operations, proceeds from borrowings and from the proceeds of disposed assets. The 2010 capital budget of $100.1 million is expected to be funded primarily by cash flows from operations, proceeds from borrowings and from a public offering of common stock that closed in January 2010 (for further information see Note 22, Subsequent Events, to our

Consolidated and Combined Financial Statements). To the extent capital requirements exceed internal cash flows and proceeds from asset sales, debt or equity may be issued to fund these requirements. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a drop in oil and gas prices or a reduction in production or reserves could adversely affect our ability to fund capital expenditures and meet our financial obligations. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may issue additional shares of stock, subordinated notes or other debt securities to fund capital expenditures, acquisitions, to extend maturities or to repay debt.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases or decreases, there could be a corresponding increase or decrease in our operating costs, as well as an increase or decrease in revenues. Inflation has had a minimal effect on us.

Critical Accounting Policies and Recently Adopted Accounting Pronouncements

The preparation of financial statements in conformity with United States generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future cash flows, asset retirement obligations, impairment (when applicable) of undeveloped properties, the collectability of outstanding accounts receivable, fair values of financial derivative instruments, contingencies and the results of current and future litigation. Oil and natural gas estimates, which are the basis for units-of-production depletion, have numerous inherent uncertainties. The certainty of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. These prices have been volatile in the past and can be expected to be volatile in the future.

The significant estimates are based on current assumptions that may be materially affected by changes in future economic conditions such as the market prices received for sales of oil and natural gas, interest rates, and our ability to generate future income. Future changes in these assumptions may materially affect these significant estimates in the near term.

Natural Gas and Oil Reserve Quantities

Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the year ended December 31, 2009, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. For the year ended December 31, 2008, Schlumberger Consulting and Data Services evaluated the proved reserves of our Marcellus Shale properties while NSAI evaluated the proved reserves on all of our other properties. These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. The technical persons responsible for preparing our proved reserves estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. The preparation of our proved reserve estimates are

completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as intense management review and approval.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil and natural gas reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC, including the recent rule revisions designed to modernize the oil and gas company reserves reporting requirements and which we adopted effective December 31, 2009. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The certainty of our reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. Any of the assumptions inherent in these factors could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas and oil eventually recovered. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new DD&A rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.

Derivative Instruments

We use put and call options (collars) and fixed rate swap contracts to manage price risks in connection with the sale of oil and natural gas. We also use interest rate swap agreements to manage interest rate risks associated with our variable rate credit facility. We have established the fair value of all derivative instruments using estimates determined by our counterparties. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings.

For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil and natural gas production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings.

Oil and Natural Gas Property, Depreciation and Depletion

We account for natural gas and oil exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of natural gas and oil, are capitalized.

Depletion, depreciation and amortization are calculated using the units-of-production method on estimated proved developed producing oil and gas reserves at the lease or well level. In arriving at rates under the units-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review our proved reserve estimates and makes changes as needed to depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold cost and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is transferred to the associated producing properties. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of 3 to 30 years.

When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. When evaluating our unproved oil and gas properties, we utilize active market prices for similar acreage to use as a comparison tool against the carrying value of our properties. If the active market prices for similar acreage do not support our carrying values we then utilize estimates of future value that will be created from the future development of these properties. If future estimated fair value of these properties is lower than the capitalized cost, the capitalized cost is reduced to the estimated future fair value. At December 31, 2009, we recognized approximately $1.6 million of impairment on certain oil and gas properties in the Appalachian Basin.

Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.

Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property, and any remaining proceeds are recognized as a gain.

Intangible Assets

At December 31, 2009, our intangible assets consisted of $686,000 of sales agreements that are amortized using the straight line method over an estimated useful life of five years. These intangible assets resulted from the Reorganization Transactions (for additional information, see Note 1, Basis of Presentation and Principles of Consolidation, of our Consolidated and Combined Financial Statements). For the years ended December 31, 2009, 2008, and 2007, we recorded amortization expense of $266,000, $266,000 and $0, respectively. Amortization expense was recorded only for those periods following the Reorganization Transactions.

Future Abandonment Cost

Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed.

If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. During the fourth quarter of 2008, we recognized an increase of $9.2 million in the estimated present value of the asset retirement obligations. The primary factors underlying the 2008 fair value revisions were an overall increase in abandonment cost estimates, the effect of changes in inflation and discount rates used in the calculations, and changes to the estimated useful life assumptions.

Deferred Taxes

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized.

We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

Contingent Liabilities

A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. We have recognized an accrued liability of approximately $1.4 million at December 31, 2009 for the estimated cost of pending litigation matters.

Accounting Standards Not Yet Adopted

In April 2009, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Codification (“ASC”) 805-20, which amends and clarifies ASC 805 to address application issues regarding initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination. ASC 805-20 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Although we did not enter into any significant business combinations during the first 12 months of 2009, we believe ASC 805-20 may have a material impact on our future financial statements depending on the size and nature of any future business combinations that we may enter into. We adopted ASC 805-20 on January 1, 2010.

In June 2009, the FASB issued Accounting Standards Update (“ASU”) 2009-16, Accounting for Transfers of Financial Assets (“ASU 2009-16”). This statement was issued as a means to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position; financial performance; and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. This statement takes effect as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter. We adopted ASU 2009-16 as of January 1, 2010. Adoption did not have a material effect on our financial position and results of operations

In June 2009, the FASB issued ASU 2009-17, Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (“ASU 2009-17”) which was issued to improve financial reporting by enterprises involved with variable interest entities. This statement addresses the effects of certain provisions of FASB Interpretation No. 46(R) and constituent concerns about the application of certain key provisions of FASB Interpretation No. 46(R), including those in which the accounting and disclosures do not always provide timely and useful information about an enterprises involvement in a variable interest entity. This statement takes effect as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim reporting periods thereafter. We adopted ASU 2009-17 as of January 1, 2010. Adoption did not have a material effect on our financial position and results of operations.

Volatility of Oil and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.

We account for our natural gas and oil exploration and production activities under the successful efforts method of accounting. (for additional information, see Note 2, Summary of Significant Accounting Policies, of our Consolidated and Combined Financial Statements)

To mitigate some of our commodity price risk we engage periodically in certain other limited derivative activities, including price swaps and costless collars, to establish some price floor protection.

For the twelve month period ended December 31, 2009, the net realized gain on oil and natural gas derivatives was approximately $10.4 million, which includes a $4.6 million gain from the early settlement of oil hedges relating to the calendar year 2011. For the twelve month period ended December 31, 2008, the net realized loss on oil and natural gas derivatives was approximately $16.2. Gains and losses are reported as Gain (Loss) on Derivatives, net in the Consolidated and Combined Statements of Operations.

For the twelve month period ended December 31, 2009, the net unrealized loss on oil and natural gas derivatives was approximately $17.6 million, as compared to a net unrealized gain of approximately $43.7 million on oil and natural gas derivatives for 2008. The net unrealized gains and losses are reported as Gain (Loss) on Derivatives, net in the Consolidated and Combined Statements of Operations.

While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of oil and natural gas. We enter into the majority of our derivative transactions with one counterparty and have a netting agreement in place with that counterparty. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional

risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivative arrangements generally do not apply to all of our production, and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time.

For a summary of our current oil and natural gas derivative positions at December 31, 2009, refer to Note 9, Fair Value of Financial Instruments and Derivative Instruments, of our Consolidated and Combined Financial Statements.

Contractual Obligations

In addition to our capital expenditure program, we are committed to making cash payments in the future on two types of contracts: note agreements and operating leases. As of December 31, 2009, we do not have any off-balance sheet debt or other such unrecorded obligations and we have not guaranteed the debt of any other party. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2009. In addition to the contractual obligations listed in the table below, our balance sheet at December 31, 2009 reflects accrued interest on our bank debt of $29,389 which is payable in January 2010.

The following summarizes our contractual financial obligations for continuing operations at December 31, 2009 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities.


	Payment due by period (in Thousands)
	2010		2011		2012		2013		2014		Thereafter		Total
Bank Debt	$	—	$	—	$	23,000	$	—	$	—	$	—	$	23,000
Operating Leases		452		454		456		479		—		—		1,841
Drilling Commitments		—		—		—		—		5,750		—		5,750
Long-Term Financing		317		28		21		—		—		—		366
Leasing Commitments		1,707		1,707		3,710		—		—		—		7,124
Derivative Obligations(1)		6,692		426		—		—		—		—		7,118
Asset Retirement Obligations		748		425		363		395		315		13,897		16,143

Total Contractual Obligations	$	9,916	$	3,040	$	27,550	$	874	$	6,065	$	13,897	$	61,342

(1)	Derivative obligations represent net open derivative contracts valued as of December 31, 2009.

Interest Rates

At December 31, 2009, we had $23.0 million of debt outstanding. This bears interest at floating rates, which averaged 2.0% at December 31, 2009. The 30-day London Interbank Offered Rate (“LIBOR”) on December 31, 2009 was 0.2%.

Off-Balance Sheet Arrangements

We do not currently use any off-balance sheet arrangements to enhance our liquidity or capital resource position, or for any other purpose.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial amount of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our

operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. Conversely, increases in the market prices for oil and natural gas can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2009 reserve estimates, we project that a 10% decline in the price per barrel of oil and the price per Mcf of gas from year end 2009 would reduce our gross revenues, before the effects of derivatives, for the year ending December 31, 2010 by approximately $4.8 million.

We have designed our hedging policy to reduce the risk of price volatility for our production in the natural gas and crude oil markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include swaps and collars. The volume of derivative instruments that we may use are governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production, and will provide only partial price protection against declines in oil and natural gas prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of oil and natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties should default, this protection might be limited as we might not receive the benefits of the hedges.

At December 31, 2009, the following commodity derivative contracts were outstanding:


Period(1)	Contract Type	Volume	Average Derivative Price		Fair Market Value ($ in Thousands)
Oil
2010	Swaps	180,000 Bbls		$62.20	$	(3,615	)
2010	Collars	408,000 Bbls		$62.94 – 86.85	$	(2,169	)
2011	Collars	228,000 Bbls		$63.42 –108.87	$	(400	)
2011	Collars	72,000 Bbls	$	60.00 –127.00	$	5

	Total	888,000 Bbls			$	(6,179	)
Natural Gas
2010	Swaps	120,000 Mcf		$6.00	$	25
2010	Collars	2,160,000 Mcf		$6.31 – 9.07	$	1,900
2011	Collars	1,800,000 Mcf		$6.47 – 10.47	$	1,560
2012	Collars	600,000 Mcf		$5.60 – 7.86	$	84

	Total	4,680,000 Mcf			$	3,569

(1)

Item 305 (a) of Regulation S-K requires that tabular information relating to contract terms allow readers of the table to determine expected cash flows from the market risk sensitive instruments for each of the next five years. At December 31, 2009, we had commodity derivative contracts in place for the next three years, relating to production through 2012.

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and prime rate based, as determined by our lenders, and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our obligations. We use the interest rate swap agreement to manage risk associated with interest payments on amounts outstanding from variable rate borrowings under our senior credit facility. Under our interest rate swap agreement, we agree to pay an amount equal to a specified rate of interest times a notional principal amount, and to receive in return, a specified variable rate of interest times the same notional principal amount.

As of December 31, 2009, the following interest rate swap derivative was outstanding ($ in thousands):


Period(1)	Contract Type	Amount		Interest Rate	Fair Market Value
1/1/10 – 11/30/10	Swap	$	20,000	4.15%	$	(711	)

(1)

Item 305 (a) of Regulation S-K requires that tabular information relating to contract terms allow readers of the table to determine expected cash flows from the market risk sensitive instruments for each of the next five years. At December 31, 2009, we had an interest rate swap derivative contract in place that expires on November 30, 2010.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REX ENERGY CORPORATION

INDEX TO FINANCIAL STATEMENTS


		Page
Report of Independent Registered Public Accounting Firm—Financial Statements		67
Consolidated Balance Sheets at December 31, 2009 and 2008		68
Consolidated and Combined Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007		69
Consolidated and Combined Statements of Changes in Stockholders’ Equity (Deficit) and Noncontrolling Interests for the Years Ended December 31, 2009, 2008 and 2007		70
Consolidated and Combined Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		71
Notes to the Consolidated and Combined Financial Statements		72

Report of Independent Registered Public Accounting Firm

To the Board of Directors and

Stockholders of

Rex Energy Corporation

State College, Pennsylvania

We have audited the accompanying Consolidated Balance Sheets of Rex Energy Corporation as of December 31, 2009 and 2008, and the related Consolidated and Combined Statements of Operations, owners’ equity (deficit) and noncontrolling interests, and cash flows of Rex Energy Corporation and Predecessor Companies for each of the years in the three-year period ended December 31, 2009. We have also audited Rex Energy Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Rex Energy Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Rex Energy Corporation as of December 31, 2009 and 2008, and the consolidated and combined results of operations, owners’ equity (deficit) and noncontrolling interest, and cash flows of Rex Energy Corporation and Predecessor Companies for each of the years in the three-year period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, Rex Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Malin, Bergquist & Company, LLP

Pittsburgh, Pennsylvania

March 3, 2010

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in Thousands, Except Per Share Data)


	December 31, 2009			December 31, 2008
ASSETS
Current Assets
Cash and Cash Equivalents	$	5,582		$	7,046
Accounts Receivable		14,333			5,840
Short-Term Derivative Instruments		2,124			8,153
Deferred Taxes		2,827			—
Inventory, Prepaid Expenses and Other		1,111			3,068

Total Current Assets		25,977			24,107

Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		206,676			185,108
Unevaluated Oil and Gas Properties		80,218			65,564
Other Property and Equipment		25,082			19,388
Wells and Facilities in Progress		34,086			29,629
Pipelines		5,167			3,457

Total Property and Equipment		351,229			303,146
Less: Accumulated Depreciation, Depletion and Amortization		(75,968	)		(53,288	)

Net Property and Equipment		275,261			249,858
Assets Held for Sale		—			18,852
Intangible Assets and Other Assets—Net		1,199			1,628
Long-Term Derivative Instruments		1,673			7,561
Investment in RW Gathering		840			—

Total Assets	$	304,950		$	302,006

LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	16,386		$	7,180
Accrued Expenses		9,333			7,388
Short-Term Derivative Instruments		6,692			—
Current Deferred Tax Liability		—			2,785

Total Current Liabilities		32,411			17,353

Senior Secured Line of Credit and Long-Term Debt		23,049			15,000
Long-Term Derivative Instruments		426			1,476
Long-Term Deferred Tax Liability		6,894			11,995
Other Deposits and Liabilities		5,830			7,322
Liabilities Related to Assets Held for Sale		—			1,838
Future Abandonment Cost		16,143			15,174

Total Liabilities		84,753			70,158
Commitments and Contingencies (See Note 7)
Owners’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 36,817,812 shares issued and outstanding on December 31, 2009 and 36,589,712 shares issued and outstanding on December 31, 2008		37			37
Additional Paid-In Capital		292,372			291,133
Accumulated Deficit		(75,555	)		(59,322	)

Rex Energy Owners’ Equity		216,854			231,848
Noncontrolling Interests		3,343			—

Total Owners’ Equity		220,197			231,848

Total Liabilities and Owners’ Equity	$	304,950		$	302,006

See accompanying summary of accounting policies and notes to the financial statements

REX ENERGY CORPORATION

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

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


	Rex Energy Corporation Consolidated			Rex Energy Corporation Consolidated			Rex Energy Corporation Consolidated and Combined Predecessor Companies
	Year Ended December 31,
	2009			2008			2007
Statement of Operations Data:
Operating Revenues:
Oil and Natural Gas Sales	$	48,534		$	84,013		$	58,133
Other Revenue		157			123			101

Total Operating Revenues		48,691			84,136			58,234

Operating Expenses:
Production and Lease Operating Expense		22,157			26,511			22,361
General and Administrative		15,858			15,185			7,793
Impairment Expense		1,625			71,349			—
(Gain) Loss on Disposal of Assets		427			6,468			(12	)
Exploration Expense		2,080			3,261			1,238
Depletion, Depreciation, Amortization and Accretion		25,205			37,904			17,804

Total Operating Expenses		67,352			160,678			49,184

Income (Loss) from Operations		(18,661	)		(76,542	)		9,050

Other Income (Expense):
Interest Income		7			328			15
Interest Expense		(833	)		(1,091	)		(5,665	)
Gain (Loss) on Derivatives, net		(7,913	)		27,328			(32,429	)
Other Expense		(170	)		(168	)		(18	)

Total Other Income (Expense)		(8,909	)		26,397			(38,097	)
Loss from Continuing Operations Before Income Taxes		(27,570	)		(50,145	)		(29,047	)
Income Tax Benefit		11,002			9,167			7,365

Loss from Continuing Operations		(16,568	)		(40,978	)		(21,682	)
Income (Loss) from Discontinued Operations, Net of Income Taxes		323			(7,704	)		(681	)

Net Loss		(16,245	)		(48,682	)		(22,363	)
Net Loss Attributable to Noncontrolling Interests		(12	)		—			(6,152	)

Net Loss Attributable to Rex Energy	$	(16,233	)	$	(48,682	)	$	(16,211	)

Earnings per common share—basic and diluted(1):
Loss from continuing operations attributable to Rex common shareholders	$	(0.45	)	$	(1.18	)	$	(0.37	)
Income (loss) from discontinued operations attributable to Rex common shareholders		0.01			(0.22	)		0.02

Net loss attributable to Rex common shareholders	$	(0.44	)	$	(1.40	)	$	(0.35	)

Weighted average shares of common stock outstanding, basic and diluted		36,806			34,595			30,795

(1)	Earnings per common share for 2007 represents a loss from continuing operations of $11,304 and a gain from discontinued operations of $664 for the 5-month period ended December 31, 2007.

See accompanying summary of accounting policies and notes to the financial statements

REX ENERGY CORPORATION

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS

($ in Thousands, Except Per Share Data)


	Common Stock	Additional Paid-In Capital	Accumulated Deficit		Other Comprehensive Income		Members’ Equity		Partners’ Equity		Total Owners’ Equity		Noncontrolling Interests
BALANCE December 31, 2006	1	1,460	(580	)	—		5,969		(7,467	)	(617	)	36,589
NET INCOME (LOSS) Before Reorganization	—	—	373		—		(4,002	)	(1,943	)	(5,572	)	(6,152	)
CAPITAL CONTRIBUTIONS Before Reorganization	—	—	—		—		—		820		820		300
DISTRIBUTIONS Before Reorganization	—	—	—		—		—		(294	)	(294	)	(1,830	)
REDEMPTION Before Reorganization	—	—	—		—		—		—		—		(7,970	)
REORGANIZATION and acquisition of noncontrolling interests effected through the exchange of 21,994,702 shares of common stock for partnership interests and shares of Predecessor Companies to Rex Energy Corporation	21	85,667	207		—		(1,967	)	8,884		92,812		(20,937	)
ISSUANCE of 8,800,000 shares of common stock net of issuance costs of $9.0 million	9	87,831	—		—		—		—		87,840		—
Unrealized loss on interest rate swap agreements, net of tax of $84	—	—	—		(124	)	—		—		(124	)	—
Non-cash compensation expense	—	212	—		—		—		—		212		—
NET LOSS After Reorganization	—	—	(10,640	)	—		—		—		(10,640	)	—

BALANCE December 31, 2007	31	175,170	(10,640	)	(124	)	—		—		164,437		—
ISSUANCE of 5,775,000 shares of common stock net of issuance costs of $6.8 million	6	112,987	—		—		—		—		112,993		—
Reclassification into earnings of interest rate swap, net of tax of $84	—	—	—		124		—		—		124		—
Non-cash compensation expense	—	2,976	—		—		—		—		2,976		—
NET LOSS	—	—	(48,682	)	—		—		—		(48,682	)	—

BALANCE December 31, 2008	37	291,133	(59,322	)	—		—		—		231,848		—
Non-cash compensation expense	—	1,239	—		—		—		—		1,239		—
Capital Contributions	—	—	—		—		—		—		—		3,355
NET LOSS	—	—	(16,233	)	—		—		—		(16,233	)	(12	)

BALANCE December 31, 2009	37	292,372	(75,555	)	—		—		—		216,854		3,343

See accompanying summary of accounting policies and notes to the financial statements

REX ENERGY CORPORATION

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

($ in Thousands)


	Rex Energy Corporation Consolidated			Rex Energy Corporation Consolidated			Rex Energy Corporation Consolidated and Combined Predecessor Companies
	For the Years Ended December 31,
	2009			2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(16,233	)	$	(48,682	)	$	(16,211	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Noncontrolling Interest Share of Loss		(12	)		—			(6,152	)
Non-cash Expenses		1,906			3,250			224
Depreciation, Depletion, Amortization and Accretion		25,205			39,469			19,622
Deferred Income Tax Benefit		(10,713	)		(10,903	)		(7,017	)
Unrealized (Gain) Loss on Derivatives		17,002			(43,188	)		26,250
Exploration Expense		135			2,200			2,948
(Gain) Loss on Sale of Oil and Gas Properties		427			6,508			(185	)
Impairment of Oil and Gas Properties		1,625			47,378			—
Impairment of Goodwill		—			32,700			—
Changes in operating assets and liabilities, net of effects from acquisitions
Accounts Receivable		(7,995	)		2,978			(1,931	)
Inventory, Prepaid Expenses and Other Assets		344			9			132
Accounts Payable and Accrued Expenses		8,801			1,425			26
Net Changes in Other Assets and Liabilities		282			(716	)		(151	)

NET CASH PROVIDED BY OPERATING ACTIVITIES		20,774			32,428			17,555
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Ventures		3,120			—			—
Investments in Joint Ventures		(309	)		—			—
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		17,998			8,826			239
Acquisitions of Undeveloped Acreage		(17,898	)		(54,914	)		(7,663	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(32,972	)		(81,712	)		(32,678	)

NET CASH USED IN INVESTING ACTIVITIES		(30,061	)		(127,800	)		(40,102	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Other Loans and Notes Payable		27,000			29,000			46,615
Repayments of Long-Term Debt and Other Loans and Notes Payable		(19,000	)		(41,296	)		(105,269	)
Repayments of Loans and Other Notes Payable		(177	)		—			—
Net (Repayments to) Proceeds from Related Parties		—			—			(1,000	)
Repayment of Participation Liability		—			—			(2,141	)
Debt Issuance Costs		—			—			(1,222	)
Proceeds from the Issuance of Common Stock, Net of Issuance Costs		—			112,993			87,860
Proceeds from Lease Incentives		—			636			—
Capital Contributions by the Partners of the Predecessor Companies		—			—			300
Cash Distributions to the Partners of the Predecessor Companies		—			—			(2,111	)

NET CASH PROVIDED BY FINANCING ACTIVITIES		7,823			101,333			23,032
NET INCREASE (DECREASE) IN CASH		(1,464	)		5,961			485
CASH—BEGINNING		7,046			1,085			600
CASH—ENDING	$	5,582		$	7,046		$	1,085
SUPPLEMENTAL DISCLOSURES
Cash Paid for Income Taxes		—			—			—
Interest Paid		581			945			5,937
NON-CASH ACTIVITIES
Acquisition of Oil and Gas Properties		—			7,970			—
Redemption-Property Distribution		—			—			7,970
Conversion of Loan Payable to Capital		—			—			820
Equipment Financing		542			—			—
Acquisition of Equipment via Noncontrolling Interests		3,342			—			—
NON-CASH ACTIVITIES RELATED TO THE REORGANIZATION:
Step-Up of Asset Basis Resulting from the Acquisition of Noncontrolling Interests		—			—			71,876
Recordation of Goodwill		—			—			32,700

See accompanying summary of accounting policies and notes to the financial statements

REX ENERGY CORPORATION AND PREDECESSOR COMPANIES

NOTES TO THE CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation (the “Company”) is an independent oil and gas company operating in the Appalachian Basin and the Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale drilling projects. In the Illinois Basin, in addition to our developmental conventional oil drilling, we are focused on the implementation of enhanced oil recovery on our properties. We pursue a balanced growth strategy of exploiting our sizable inventory of lower-risk developmental drilling locations, pursuing our higher potential exploration drilling prospects, and actively seeking to acquire complementary oil and natural gas properties.

We refer to certain companies—Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, New Albany-Indiana, LLC, PennTex Resources, L.P., PennTex Resources Illinois, Inc., Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy III LLC, Rex Energy IV, LLC, Rex Energy II Alpha Limited Partnership, Rex Energy Operating Corp. and Rex Energy Royalties Limited Partnership—collectively as the “Predecessor Companies.” We refer to each of the Predecessor Companies individually as:


Douglas Oil & Gas Limited Partnership		“Douglas Oil & Gas”
Douglas Westmoreland Limited Partnership		“Douglas Westmoreland”
Rex Energy Royalties Limited Partnership		“Rex Royalties”
Midland Exploration Limited Partnership		“Midland”
New Albany-Indiana, LLC		“New Albany”
PennTex Resources Illinois, Inc		“PennTex Illinois”
PennTex Resources, L.P		“PennTex Resources”
Rex Energy Limited Partnership		“Rex I”
Rex Energy II Limited Partnership		“Rex II”
Rex Energy II Alpha Limited Partnership		“Rex II Alpha”
Rex Energy III LLC		“Rex III”
Rex Energy IV, LLC		“Rex IV”
Rex Energy Operating Corp.		“Rex Operating”

Simultaneously with the consummation of our initial public offering of common stock, through a series of mergers and reorganization transactions, which we refer to as the “Reorganization Transactions,” Rex Energy Corporation acquired all of the outstanding equity interests of the Predecessor Companies. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and subsidiaries together with the Predecessor Companies, after giving effect to the Reorganization Transactions.

The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include (1) subsequent to the reorganization as described below, the consolidated accounts of Rex Energy Corporation and (2) prior to the reorganization the Predecessor Companies, the combined accounts of the Predecessor Companies under the common ownership of Lance T. Shaner. The consolidated and combined financial statements include the accounts of all of our subsidiaries. All material intercompany balances and transactions have been eliminated.

Certain prior year amounts have been reclassified to conform to the report classifications for the year ended December 31, 2009, with no effect on previously reported net income, net income per share, accumulated deficit or stockholders’ equity. Approximately $11.0 million of valuation allowance related to the impairment of our evaluated oil and gas assets at December 31, 2008 was reclassified from Evaluated Oil and Gas Properties on the balance sheet to Accumulated Depreciation, Depletion and Amortization (“DD&A”). Losses of approximately

$16.2 million and $6.2 million for the years ended December 31, 2008 and 2007 have been reclassified from Realized Loss on Derivatives on the Statements of Operations to Gain (Loss) on Derivatives, Net. Additionally, approximately $251,000 in expense and $19,000 of income for the years ended December 31, 2008 and 2007 have been reclassified from Interest Expense on the Statements of Operations to Gain (Loss) on Derivatives, net. Previously, we had recorded realized settlements on commodity derivatives as a source of revenue and realized settlements on our interest rate swap as interest expense.

The combined financial statements of the Predecessor Companies reflect the assets, liabilities, revenues, expenses and cash flows on a gross basis, and the economic interests not owned by Lance T. Shaner are reflected as noncontrolling interests. All of the Predecessor Companies were under the common control of Lance T. Shaner, our Chairman, through his direct and indirect ownership interests and other contractual arrangements, as well as under the common management of Rex Energy Operating Corp.

On July 30, 2007, we reorganized by acquiring all of the outstanding equity interests of each of the Predecessor Companies through a series of mergers and Reorganization Transactions. The Reorganization Transactions occurred simultaneously with the consummation of our initial public offering of common stock. The Reorganization Transactions were accounted for partially as an exchange of entities under common control for the interests in the Predecessor Companies which were contributed by Lance T. Shaner, and partially as an acquisition of noncontrolling interests using the purchase method of accounting for all the predecessor owners other than Lance T. Shaner.

The initial public offering of shares of common stock consisted of 8,800,000 shares of common stock offered and sold by us at an offering price of $11.00 per share. We received gross proceeds from the offering of $96.8 million and incurred approximately $9.0 million in underwriting discounts, commissions, and offering costs associated with the offering.

The Reorganization Transactions resulted in our recognition of the acquisition of minority ownership interests and an associated increase in the book basis of certain property assets. These assets are subject to depletion and amortization expenses. The reorganization also resulted in our becoming subject to federal and state income taxes. Tax expenses had previously passed through to the equity owners of the Predecessor Companies and were not recorded on the books of the Predecessor Companies.

On May 5, 2008, we completed a public offering of 9.8 million shares of common stock at an offering price of $20.75 per share. These shares included 5.8 million shares offered by us (which includes 1.3 million shares sold pursuant to the exercise of an overallotment option granted to the underwriters’ of the offering) and 4.0 million shares sold by certain selling stockholders. The net proceeds of the underwritten public offering, after underwriting discounts and offering expenses of approximately $6.8 million, were approximately $113.0 million.

On November 12, 2009, we entered into a limited liability agreement with Sand Hills Management, LLC (“Sand Hills”) to form Water Solutions Holdings, LLC (“Water Solutions Holdings”) for the purpose of acquiring, managing and operating water treatment, water disposal and water transportation facilities that are designed to treat, dispose or transport brine and other waste waters produced in oil and gas well development activities. The members of Water Solutions Holdings are Rex Energy Corporation, which owns and 80% membership interest, and Sand Hills, which owns a 20% membership interest. Pursuant to the limited liability company agreement, we contributed our 100% membership interest in Keystone Clearwater Solutions, LLC (“Keystone Clearwater”), which had an equity balance of approximately $403,000. Sand Hills contributed approximately $88,000 in capital assets and will contribute approximately $13,000 in cash.

We have identified Water Solutions Holdings as a variable interest entity (“VIE”) due to the lack of sufficient equity at risk to permit the entity to finance its activities without additional subordinated financial support. As the 80% interest owner in this entity, we are exposed to the majority of the variability in the expected losses and returns, and are thus considered the primary beneficiary. Based on these factors, it was determined that

we are required to consolidate the financial statements of Water Solutions Holdings. The equity and capital assets contributed by Rex and Sand Hills, respectively, are currently classified as Wells and Facilities in Progress on our Consolidated Balance Sheets. The cash contribution to be made by Sand Hills is classified as Accounts Receivable on our Consolidated Balance Sheets. As of December 31, 2009, no creditors have provided financing to Water Solutions Holdings; therefore there is no recourse to the general credit of Rex Energy (for additional information, see Note 7, Related Party Transactions, of our Consolidated and Combined Financial Statements).

On December 21, 2009, we entered into a midstream joint venture with Stonehenge Energy Resources, L.P. (“Stonehenge”) to be operated as Keystone Midstream Services, LLC (“Keystone Midstream”). The venture will be principally focused on building, operating and owning a high pressure gathering system and cryogenic gas processing plant in Butler County, Pennsylvania. The members of Keystone Midstream are R.E. Gas Development, LLC (“R.E. Gas”), which owns a 40% interest, and Stonehenge, which owns a 60% interest. Pursuant to the terms of the limited liability company agreement and contribution agreement entered into by R.E. Gas and Stonehenge at the time of the formation of the joint venture, (a) R.E. Gas contributed to Keystone Midstream (i) a 16.3% undivided interest in a skid-mounted cryogenic natural gas processing plant (the “Gas Processing Plant”) valued at $740,000 and (ii) an option to purchase R.E. Gas’s existing gas gathering system in Butler County, Pennsylvania valued at $1.8 million, and (b) Stonehenge contributed to Keystone Midstream the remaining 83.7% undivided interest in the Gas Processing Plant valued at $3.8 million, of which approximately $3.3 million had been paid for as of December 31, 2009.

We have identified Keystone Midstream to be a VIE because the holders of equity at-risk are protected from the first dollar risk of loss associated with one of the predominant risks of the entity through the pricing terms of a leasing arrangement with Rex. We determined that R.E. Gas is the primary beneficiary of the VIE because they are subject to the majority of the economic variability in Keystone Midstream due primarily to the priority capacity reservation fee to be paid under the gas processing agreement between R.E. Gas and Keystone Midstream. Based on these factors, it was determined that we are required to consolidate the financial statements of Keystone Midstream. Assets contributed by both parties have been consolidated as Wells and Facilities in Progress on our Consolidated Balance Sheets. As of December 31, 2009, no creditors have provided financing to Keystone Midstream; therefore there is no recourse to the general credit of Rex Energy (for additional information, see Note 7, Related Party Transactions, of our Consolidated and Combined financial statements).

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates made in preparing these consolidated and combined financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates and our ability to generate future income.

Cash and Cash Equivalents

We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents.

Accounts Receivable

Our trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and recorded bad debts as necessary.

We use the allowance method to account for uncollectible accounts receivable. A reserve is recorded for amounts we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. The reserve of $173,000 at January 1, 2007 increased by $12,000 due to bad debt expense and there were no write offs during calendar year 2007. The reserve of $185,000 at January 1, 2008 increased by $115,000 of bad debt expense and there were $163,000 of write offs during calendar year 2008. The reserve of $137,000 at January 1, 2009 increased by $43,000 due to bad debt expense and there were $24,000 of write offs during calendar year 2009. Accordingly, the allowance for uncollectible receivables was $156,000 at December 31, 2009. A summary of our reserve for uncollectible accounts receivable is provided in the table below ($ in thousands):


Description	Balance at Beginning of Year		Additions Charged to Expense		Recoveries		Deductions		Balance at Year-End
Year ended December 31, 2007
Allowance for doubtful accounts—A/R	$	173	$	12	$	—	$	—	$	185
Year ended December 31, 2008
Allowance for doubtful accounts—A/R	$	185	$	115	$	—	$	163	$	137
Year ended December 31, 2009
Allowance for doubtful accounts—A/R	$	137	$	43	$	—	$	24	$	156

To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying financial statements.

At December 31, 2009, we carried approximately $6.3 million in production receivable, of which approximately $4.2 million were production receivables due from a single customer, CountryMark Cooperative LLP. At December 31, 2008, we carried approximately $4.2 million in production receivable, of which approximately $2.5 million were production receivables due from a single customer, CountryMark Cooperative LLP.

Inventory

Inventory is valued at the lower of cost or market value and consists of our ownership interest in oil and NGLs held in terminal tanks located in the field. Oil and NGL inventory is accounted for using the average cost method, with average cost defined as production and lease operating expenses net of depreciation, depletion and amortization. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory.

Oil and Natural Gas Property, Depreciation and Depletion

We account for natural gas and oil exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by- property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development well and related equipment used in the production of natural gas and oil, are capitalized.

Depletion, depreciation and amortization are calculated using the unit-of-production method on estimated proved oil and gas reserves at the lease, unit or well level. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion, depreciation and amortization expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved developed producing reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 30 years.

Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.

Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depreciation, depletion and amortization are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved

leaseholds for cash or cash equivalents, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Natural Gas and Oil Reserve Quantities

Intangible Assets

At December 31, 2009, our intangible assets consisted of $1.1 million which is primarily made up of sales agreements that are amortized using the straight line method over their respective estimated lives, which is, on average, five years. These intangible assets resulted from the Reorganization Transactions (for additional information, see Note 1, Basis of Presentation and Principles of Consolidation, of our Consolidated and Combined Financial Statements). For the years ended December 31, 2009, 2008, and 2007, we recorded amortization expense of $0.4 million, $0.4 million and $1.4 million, respectively. Amortization expense was recorded only for those periods following the Reorganization Transactions. The aggregate estimated annual amortization expense for each of the next five calendar years is as follows: 2010—$0.4 million; 2011—$0.4 million; 2012—$0.3 million; 2013—$0; and 2014—$0.

The following is a summary of intangible assets at the dates indicated (in thousands):


	December 31, 2009			December 31, 2008
Intangible Assets—Gross	$	2,107		$	2,097
Accumulated Amortization		(1,009	)		(591	)

Intangible Assets—Net	$	1,098		$	1,506

Future Abandonment Cost


	December 31, 2009 ($ in Thousands)			December 31, 2008 ($ in Thousands)
Beginning Balance	$	16,284		$	6,396
Asset Retirement Obligation Incurred		254			364
Asset Retirement Obligation Settled		(618	)		(512	)
Asset Retirement Obligation Cancelled or Sold Well Properties		(1,230	)		(116	)
Asset Retirement Obligation Revision of Estimated Obligation		—			9,204
Asset Retirement Obligation Accretion Expense		1,453			948

Total Asset Retirement Obligation	$	16,143		$	16,284

Revenue Recognition

Oil and natural gas revenue is recognized when the oil or natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil sales, title is transferred to the purchaser when the oil leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil or gas purchased (although there are provisions for challenging these measurements if we believe the measuring instruments are faulty). Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil and natural gas production is at its applicable field gathering system; therefore, we do not incur transportation costs related to our sales of oil and natural gas production. We do not currently participate in any gas-balancing arrangements. We do not recognize revenue for oil production held in stock tanks before delivery to the purchaser.

Derivative Instruments

We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designed as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings.

Income Taxes

Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted marginal tax rate. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized.

This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Additionally, we establish reserves for uncertain tax positions based upon our judgment regarding potential future challenges to those positions. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position.

The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. These deferred tax assets consist primarily of net operating losses and deductible temporary differences.

The accounting estimates related to the liability for uncertain tax positions require us to make judgments regarding the sustainability of each uncertain tax position based on its technical merits. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our consolidated financial statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 10, Income Taxes, to our Consolidated and Combined financial statements).

Advertising Expense

Advertising costs are expensed as incurred and were approximately $20,000, $81,000 and $27,000 for the years ended December 31, 2009, 2008, and 2007, respectively.

Loan Costs

Loan costs consisted of gross debt issuance costs of approximately $743,000, $770,000 and $690,000 for the years ended December 31, 2009, 2008 and 2007, which are presented net of accumulated amortization of $356,000, $215,000 and $42,000, respectively. Loan costs at December 31, 2009 are included in Intangible and Other Assets on the Consolidated Balance Sheets and are amortized over five years.

Stock-based Compensation

We recognize in the financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options.

The benefits associated with the tax deductions in excess of recognized compensation cost are reported as a financing cash flow. This requirement reduces net operating cash flows and increases net financing cash flows. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 14, Employee Benefit Plans and Equity Plans, to our Consolidated and Combined Financial Statements).

Earnings Per Share

Earnings per common share are computed by dividing consolidated net income by the weighted average number of common shares outstanding. Diluted earnings per common share are computed by dividing consolidated net income by the weighted average number of common shares outstanding during the period, including any potentially dilutive outstanding securities, such as options and warrants. The potentially dilutive outstanding securities are calculated using the treasury stock method. Earnings per share are reflected prospectively from August 1, 2007, the date the Predecessor Companies were acquired by Rex Energy Corporation. Therefore, at December 31, 2007, we had consolidated operations for only five months in the fiscal year period for which earnings per share are relevant. At December 31, 2009, we had 36,817,812 common shares outstanding, 873,838 options outstanding and 73,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities.

Before the Reorganization Transactions, our business was conducted through a group of entities for which there was no single holding entity. Each entity was separately owned by its then existing owners. As a result, there was no single capital structure upon which to calculate historical earnings per share information. Accordingly, earnings per share information has not been presented for historical periods before the Reorganization Transactions.

Capital Leases

As a lessee, we determine if a lease is a capital lease if it meets one of four of the following criteria:

•

The ownership of the leased property transfers to us by the end of the lease term, or shortly thereafter, in exchange for the payment of a nominal fee.

•

The lease contains a bargain purchase option.

•

The lease term is equal to 75% or more of the estimated economic life of the leased property.

•

The present value at the beginning of the lease term of the minimum lease payments, excluding that portion of the payments representing executor costs such as insurance, maintenance, and taxes to be paid by the lessor, including any profit thereon, equals or exceeds 90% of the excess of the fair value of the leased property to the lessor at the lease inception over any related investment tax credit retained by the lessor and expected to be realized by the lessor.

As of December 31, 2009 we had capital leases on 17 trucks being used in our Illinois Basin. We initially recorded these leases as Other Property and Equipment on our Consolidated Balance Sheet in the amount of $0.5 million. The remaining obligation to be paid on these leases totaled approximately $0.3 million and was classified as Accounts Payable under Current Liabilities on our Consolidated Balance Sheets, all of which is expected to be paid in 2010. We recorded approximately $49,000 of amortization on these vehicles, classified as Depletion, Depreciation, Amortization and Accretion on our Consolidated and Combined Statements of Operations. Prior to 2009, we had no assets classified as capital leases.

Recently Issued Accounting Pronouncements

In April 2009, the FASB issued ASC 805-20, which amends and clarifies ASC 805 to address application issues regarding initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination. ASC 805-20 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Although we did not enter into any significant business combinations during 2009, we believe ASC 805-20 may have a material impact on our future financial statements depending on the size and nature of any future business combinations that we may enter into. We adopted ASC 805-20 on January 1, 2010.

Recently Adopted Accounting Pronouncements

In December 2008, the SEC adopted rule changes to modernize its oil and gas reporting disclosures. The changes are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. The updated disclosure requirements are designed to align with current practices and changes in technology that have taken place in the oil and gas industry since the adoption of the original reporting requirements more than 25 years ago.

New disclosure requirements include: permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; enabling companies to also disclose their probable and possible reserves to investors (previously, the rules limited disclosure to only proved reserves); allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves; requiring companies to report on the independence and qualifications of a preparer or auditor and requiring companies to file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit; and requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period, rather than the year-end price, to maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

The new requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The adoption of the new SEC rules had a material impact on our disclosures and results of operations.

Our proved reserve estimates as of December 31, 2009 were evaluated based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2009. Under previous guidance, pricing was based on the year-end commodity prices. The average prices for oil and natural gas during the year were lower than the prices at year-end, causing our proved reserves to be lower than they would have been under the previous rules. The amount of our proved reserves impacts our accounting for DD&A, which is calculated on a units-of-production basis and typically increases when proved reserves are lower and decreases when proved reserves are higher. For a quantitative analysis of the overall changes in reserves from prior years, see Note 18, Oil and Natural Gas Reserve Quantities (Unaudited), to our Consolidated and Combined Financial Statements.

On January 1, 2009, we adopted the provisions of FASB ASC 815-10, which requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. Entities are required to provide enhanced disclosures about: (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedged items are accounted for under FASB ASC 815 and its related interpretations; and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. See Note 9, Fair Value of Financial Instruments and Derivative Instruments, for our disclosures required under FASB 815-10.

Effective January 1, 2009, we adopted FASB ASC 805-10, which establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any non-controlling interest in the acquiree. The statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. FASB ASC 805-10 also provides guidance for recognizing changes in an acquirer’s existing tax valuation allowances and tax uncertainty accruals that result from a business combination transaction as adjustments to income tax expense. We believe FASB 805-10 may have a material impact on future consolidated financial statements, depending on the size and nature of any future business combinations that we may enter into, any future adjustments made to tax valuation allowances and uncertainty accruals related to business combinations entered into prior to January 1, 2009. During the 12 months ended December 31, 2009,

the adoption did not have an impact on adjustments made to tax valuation allowances and uncertainty accruals related to business combinations entered into prior to January 1, 2009.

Effective January 1, 2008, we adopted FASB ASC 820-10 with respect to our financial assets and liabilities. In February 2008, the FASB issued further provisions to FASB 820-10, which provided a one year deferral of the effective date of FASB ASC 820-10 for non-financial assets and non-financial liabilities, except those that are recognized or disclosed in the financial statements at fair value at least annually. Therefore, we adopted the new provisions of FASB ASC 820-10 for non-financial assets and non-financial liabilities effective January 1, 2009. However, adoption of FASB ASC 820-10 for non-financial assets and non-financial liabilities did not have a material impact on our consolidated results of operations or financial condition.

In April 2009, the FASB issued FASB ASC 825-10-65-1. This ASC amends FASB 825, to require disclosures about fair value of financial instruments not measured on the balance sheet at fair value in interim financial statements, as well as, in annual financial statements. Prior to this ASC, fair values for these assets and liabilities were only disclosed annually. This ASC applies to all financial instruments within the scope of FASB ASC 825 and requires all entities to disclose the method(s) and significant assumption(s) used to estimate the fair value of financial instruments. This ASC is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. An entity may early adopt this ASC only if it also elects to early adopt FASB ASC 820-10-65-4 and FASB ASC 320-10-65-1. This ASC does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this ASC requires comparative disclosures only for periods ending after initial adoption. Adoption of FASB ASC 825-10-65-1 did not have a material impact on our financial position or results of operations.

In May 2009, the FASB issued FASB ASC 855-10 which establishes general standards for and disclosure of events that occur after the balance sheet date but before financial statements are issued. FASB ASC 855-10 identifies the period after the balance sheet date that management should evaluate transactions that may occur for potential recognition or disclosure. This statement also provides circumstances under which an entity should recognize events or transactions occurring after the balance sheet in its financial statements and identifies disclosures that an entity should make about events or transactions that occur after the balance sheet date. This statement is in effect for interim or annual financial reports ending after June 15, 2009. Adoption of FASB ASC 855-10 did not have a material impact on our financial position or results of operations.

In June 2009, the FASB issued FASB ASC 105-10. This statement officially dictates that the FASB Accounting Standards Codification will become the source of authoritative U.S. generally accepted accounting principles. Following this statement, new standards will no longer be issued in the form of statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. FASB ASC 105-10 is effective for financial statements issued for reporting periods that end after September 15, 2009. Adoption of this statement did not have a material impact on our financial positions or results of operations.

In August 2009, the FASB issued ASU 2009-05, Fair Value Measurements and Disclosures (Topic 820)—Measuring Liabilities at Fair Value (“ASU 2009-05”). This update provides amendments to Subtopic 820-10, Fair Value Measurements and Disclosures—Overall, for the fair value measurement of liabilities. The update provides that a reporting entity, in circumstances in which a quoted price in an active market for the identical liability is not available, is required to measure fair value using a valuation technique that uses the quoted price of the identical liability when traded as an asset and/or another valuation technique that is consistent with the principles of Topic 820. Furthermore, this update clarifies that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. This update also states that both a quoted price in an active market for the identical liability at the measurement date and the quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. We adopted this update in the fourth quarter of 2009 and it did not have a material impact on our financial position or results of operations.

3. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS

Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our Consolidated and Combined Statements of Operations from the closing date of acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. Acquisitions are funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.

Williams Joint Venture (2009)

In the second quarter of 2009, we entered into a Participation and Exploration Agreement (the “PEA”) with Williams that was effective as of May 5, 2009. Under the terms and conditions of the PEA, Williams may acquire, through a “drill-to-earn” structure, 50% of our working interest in certain oil and gas leases covering approximately 43,672 net acres in Centre, Clearfield and Westmoreland Counties, Pennsylvania (the “Project Area”). The PEA effectively provides that, for Williams to earn its 50% interest in the Project Area, Williams will bear 90% of all costs and expenses incurred in the drilling and completion of all wells jointly drilled in the Project Area until such time as Williams has invested approximately $74.0 million (approximately $33.0 million on behalf of us and $41.0 million for Williams’ 50% share of the wells). In addition, Williams committed to participate in drilling a minimum of 10 horizontal wells in the Project Area to a depth sufficient to test the Marcellus Shale formation. Subject to certain termination rights, Williams agreed to fund its carry obligation prior to December 31, 2011 or make a cash payment to us for the remaining carry amount that has not been incurred at that time. Once Williams has completed its carry obligation and acquired 50% of our working interest in the leases within the Project Area, the parties will share all costs of the joint venture operations within an area of mutual interest (including the Project Area) in accordance with their participating interests, which are expected to be on a 50/50 basis. We believe this agreement will allow us to accelerate our activities in the Marcellus Shale while conserving capital at the same time.

In accordance with the terms of the PEA, Williams reimbursed us for approximately $3.1 million for Williams’ share of certain expenses incurred in the acquisition and development of oil and gas leases within the Project Area that we had previously paid. The PEA provides that we will continue to serve as operator of the Project Area until December 31, 2009, and thereafter, Williams will become the operator of the Project Area.

2009 Acquisitions and Leasing Activities

In the second quarter of 2009, we completed the acquisition of a 50% interest from our joint venture partner in certain oil and gas leases covering lands in Butler County, Pennsylvania for approximately $4.2 million. This acquisition gives us a 100% interest in these oil and gas leases and increases our acreage holdings by approximately 6,500 net acres in this project region. In the transaction, we acquired only undeveloped acreage and we did not assume any liabilities.

2009 Dispositions

In the first quarter of 2009, we completed the sale of certain oil and gas leases, wells and related assets located primarily in the Permian Basin in the states of Texas and New Mexico for net proceeds of approximately $17.3 million and recorded a loss of $0.4 million. We have reflected the results of these divested operations as discontinued operations rather than a component of continuing operations. For additional information, see Note 4, Discontinued Operations/Assets Held For Sale, to our Consolidated and Combined Financial Statements.

2008 Acquisitions and Leasing Activities

On May 8, 2008, our wholly owned subsidiary, R.E. Gas Development, LLC, acquired a 100% working interest in an oil and gas lease covering 5,761 net undeveloped acres in Centre County in the Commonwealth of Pennsylvania. The interest was acquired from Resource Recovery, LLC for approximately $17.4 million.

Pursuant to the oil and gas lease, $5.8 million of this amount was paid in May 2008 and $5.8 million was paid in June 2008. The remaining $5.8 million to be paid will be distributed in equal installments of approximately $1.4 million in each of the next three years with the last payment being made in 2012 (for additional information, see Note 6, Commitments and Contingencies, to our Consolidated and Combined financial statements).

On June 11, 2008, R.E. Gas Development, LLC, acquired a 100% working interest in leases covering 762 net undeveloped acres in Clearfield County in the Commonwealth of Pennsylvania. The interests were acquired from individual landowners for approximately $2.2 million. Pursuant to the leasing agreement, $1.1 million of this amount was paid in June 2008. The remaining $1.1 million payment has been deferred and will be distributed in equal installments of approximately $267,000 in each of the next three years with the last payment being made in 2012 (for additional information, see Note 6, Commitments and Contingencies, to our Consolidated and Combined Financial Statements).

On June 13, 2008, R.E. Gas Development, LLC, acquired a 100% working interest in a lease covering 5,722 net undeveloped acres in Clearfield County in the Commonwealth of Pennsylvania. The interest was acquired from E.M. Brown, Inc. for approximately $17.2 million. Pursuant to the leasing agreement, $15.2 million of this amount was paid in June 2008. The remaining $2.0 million payment has been deferred and will be paid in 2012 (for additional information, see Note 6, Commitments and Contingencies, to our Consolidated and Combined Financial Statements).

On December 16, 2008, R.E. Gas Development, LLC acquired a 100% working interest in a lease covering 470 net undeveloped acres in Clearfield County in the Commonwealth of Pennsylvania. The interest was acquired from an individual landowner for approximately $1.2 million.

Throughout the year ended December 31, 2008, our wholly owned subsidiaries, R.E. Gas Development, LLC and Rex I, LLC, acquired 100% working interests in several leases totaling 2,253 net acres in Westmoreland and Clearfield Counties in the Commonwealth of Pennsylvania. These interests were acquired from various individual landowners for a total of $2.7 million.

2008 Dispositions

During the third quarter of 2008, we sold approximately 79,000 net undeveloped acres in Indiana and certain related non-producing wells, which was a part of our New Albany Shale exploration projects, for approximately $8.4 million in proceeds. A related loss of approximately $6.3 million was recorded as a part of continuing operations on our Consolidated and Combined Statement of Operations.

Acquisition of Noncontrolling Interests (2007)

Pursuant to the Reorganization Transactions, Rex Energy Corporation acquired interests in the Predecessor Companies from the predecessor owners. These interests were acquired through an exchange of common stock in Rex Energy Corporation.

These transactions have been accounted for partially as a transfer of interests under common control and partially as an acquisition of non-controlling interests. The controlling interests of the Predecessor Companies were held by Lance T. Shaner. Those interests are reflected in the consolidated financial statements at the historical cost of the interests contributed. The non-controlling owners’ interests are accounted for using the purchase method of accounting and reflected as noncontrolling interests in the consolidated financial statements at the fair value of the interests contributed, since such holders did not control the Predecessor Companies before the Reorganization Transactions.

The total consideration paid for the noncontrolling interests was $92.8 million and reflects 8,437,521 shares of Rex Energy Corporation common stock, the fair value of which was based upon the initial public offering

price of $11.00 per share of common stock. Accordingly, we have reflected the acquired tangible assets at the fair value of the consideration paid. The excess of the purchase price and deferred tax liabilities over the fair value of the tangible assets acquired approximates $34 million as of December 31, 2007, and is included in Intangible and Other Assets—Net and Goodwill in the accompanying financial statements.

The finite-lived intangible assets related to the contractual right to future sales revenue from sales agreements was $1.3 million. The residual amount representing the purchase price in excess of tangible and intangible assets is $32.7 million which represents a net deferred tax liability, and was recorded as Goodwill. At December 31, 2008, we conducted annual impairment testing on our Goodwill and identifiable intangible assets. Our testing determined that Goodwill was impaired and we subsequently wrote down 100% of the book value to $0, which was recorded as impairment expense in our results from continuing operations.

We have determined the following fair values for the acquired assets and liabilities assumed as of the date of acquisition ($ in thousands):


Purchase Price	$	92,813

Noncontrolling interests		20,937
Goodwill		32,700
Finite-Lived Intangible Assets/Contractual Rights		1,328
Fair Value of Evaluated Property Assets		52,362
Fair Value of Unevaluated Property Assets		18,186
Deferred Tax Asset		2,300
Deferred Tax Liability		(35,000	)

Purchase Price Allocation	$	92,813

The estimated useful lives of the finite-lived intangibles are expected to be five years. We amortize these finite-lived intangibles over their estimated useful lives using the straight line method.

2007 Acquisitions and Leasing Activities

On February 26, 2007, Rex II acquired a 90.0% working interest in six oil and gas leases covering properties located in Hardin County, Texas for $1,080,000, after which time the operations have been included with those of the Company. The acquisition included interests in three producing oil wells and related infrastructure and equipment. The interests were purchased from the Creditor’s Trust for Central Utilities Production Corp., a creditor’s trust established in connection with a bankruptcy case styled In re Central Utilities Production Corp., Case No. 03-44067, filed in the United States Bankruptcy Court, Eastern District of Texas, Sherman Division. The effective date of the acquisition was February 1, 2007.

On April 17, 2007, Rex II acquired a 52.375%, and an 83.707% working interest in two oil and gas leases covering properties located in Concho County, Texas for $890,000, after which time the operations have been included with those of the Company. The acquisition included interests in 10 producing oil wells, eight water injection wells, three water supply wells, eight shut-in wells and related infrastructure and equipment. The interests were acquired from various working interest owners, including the operator of the properties, Ultra Oil & Gas Inc. Ultra Oil & Gas Inc. acted as agent for the various sellers. The effective date of the acquisition was January 1, 2007.

On May 24, 2007, Rex II acquired a 40.0% working interest in certain undeveloped oil and gas leases covering approximately 18,000 gross acres located in Knox, Daviess, Sullivan and Greene Counties in the State of Indiana. The interests were acquired from HAREXCO, Inc., an Illinois corporation doing business in the State of Indiana under the assumed name of Harris Energy Company (“Harris Energy”), for a purchase price of $1,079,000. In connection with this sale, Harris Energy reserved a 4.0% of 40.0% overriding royalty interest in

the conveyed properties and a 10.0% of 40.0% back-in-after-payout working interest in the first five net wells drilled on the acquired properties or any other properties which are subsequently acquired by Rex II from Harris Energy. In connection with the closing, Rex II and Harris Energy entered into an exploration agreement, wherein the parties created an area of mutual interest in certain areas of the above counties, and a joint operating agreement, wherein Rex II was appointed the operator of the covered properties. Rex II also agreed to purchase from Harris Energy a 40.0% working interest in certain oil and gas leasehold interests covering up to 5,878 net acres located in Knox County, Indiana. Pursuant to the agreement between the parties, Rex II was obligated to purchase an interest in only those oil and gas leases which were acquired by Harris Energy on or before August 22, 2007. The purchase price for the interest in these leases is equal to 40.0% of the product of $100.00 and the number of net leasehold acres assigned to Rex II on the closing date. In the event that Rex II purchases an interest in any of these leases, Harris Energy will also be entitled to reserve and retain the same overriding royalty interest and the back-in-after-payout working interest described above.

On September 7, 2007, our wholly owned subsidiary, Rex Energy I, LLC, acquired a 30% working interest in certain undeveloped oil and gas leases covering approximately 70,322 gross acres located in Lawrence, Orange, Washington and Jackson Counties in the State of Indiana for a purchase price of $1,055,000. The interests were acquired from Aurora Oil & Gas Corporation pursuant to an option granted to New Albany on January 27, 2006, the predecessor in interest of Rex Energy I, LLC. In connection with this sale, Aurora reserved a 0.5% overriding royalty interest in the conveyed properties.

On November 29, 2007, R.E. Gas Development, LLC, acquired a 50% working interest in multiple leases covering approximately 16,460 gross and 8,230 net undeveloped acres in Butler and Beaver Counties in the Commonwealth of Pennsylvania. The interests were purchased from Vista Resources, Inc., a Pittsburgh, Pennsylvania private oil and gas company, for $1,070,000.

2007 Dispositions

There were no significant dispositions for the year ended December 31, 2007.

4. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

On March 24, 2009, we completed the sale of certain oil and gas leases, wells and related assets predominantly located in the Permian Basin in the states of Texas and New Mexico. We received net cash proceeds of approximately $17.3 million, which may be adjusted by certain post-closing adjustments, plus the assumption of certain liabilities, based on an effective date of October 1, 2008. Upon closing of the sale, we used the proceeds to pay down our long-term borrowings on our Senior Credit Facility.

Pursuant to the accounting rules for discontinued operations, these assets were classified as Assets Held for Sale on our Balance Sheet as of December 31, 2008, and results of operations are reflected in discontinued operations in our Consolidated Statements of Operations. We recorded a loss on sale of assets of approximately $0.4 million in our Consolidated Statement of Operations. Upon closing of the sale, we recorded severance wages in discontinued operations of approximately $0.2 million for our former employees in the Southwest Region. Summarized financial information for discontinued operations is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the discontinued operations were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.


	December 31,
	2009			2008			2007
Revenues:
Oil and Gas Sales	$	193		$	6,051		$	5,392
Other Revenue		—			304			350

Total Operating Revenue		193			6,355			5,742

Costs and Expenses:
Production and Lease Operating Expense		237			1,799			2,116
General and Administrative Expense		(97	)		907			794
Exploration Expense of Oil and Gas Properties		—			2,198			1,710
Impairment Expense of Oil and Gas Properties		—			8,729			—
Depreciation, Depletion, Amortization and Accretion		—			1,565			1,817
(Gain) Loss on Sale of Oil and Gas Properties		—			41			(173	)
(Gain) Loss from Derivatives, net		(558	)		558			—
Other Income		—			(2	)		(189	)

Total Costs and Expenses		(418	)		15,795			6,075

Income (Loss) from Discontinued Operations Before Income Taxes		611			(9,440	)		(333	)
Income Tax (Expense) Benefit		(288	)		1,736			(348	)

Income (Loss) From Discontinued Operations, net of taxes	$	323		$	(7,704	)	$	(681	)

Production:
Crude Oil (Bbls)		7,507			41,332			44,946
Natural Gas (Mcf)		61,661			311,280			373,904

Total (Mcfe)		106,703			559,272			643,580

As of December 31, 2009, we did not have any assets or liabilities classified as held for sale. Of the $18.9 million in assets that are classified as held for sale as of December 31, 2008, approximately 99.4% of this value is associated with property and equipment. For the years ended December 31, 2009 and 2008, the amounts classified as liabilities related to assets held for sale are as follows:


	December 31,
	2009		2008
Liabilities Related to Assets Held for Sale:
Accounts Payable	$	—	$	169
Short-Term Derivative Instruments		—		166
Long-Term Derivative Instruments		—		392
Asset Retirement Obligation		—		1,111

Total Liabilities Related to Assets Held for Sale	$	—	$	1,838

5. CONCENTRATIONS OF CREDIT RISK

At times during the years ended December 31, 2009 and 2008, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations.

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with a high-quality counterparty. Our counterparty is an investment grade financial institution, and a lender in our Senior Credit Facility. We have a master netting agreement in place with our counterparty that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled settlement date. For additional information, see Note 9, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated and Combined Financial Statements.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At December 31, 2009, we carried approximately $6.3 million in production receivable, of which approximately $4.2 million were production receivables due from a single customer, CountryMark Cooperative LLP. At December 31, 2008, we carried approximately $4.2 million in production receivable, of which approximately $2.5 million were production receivables due from a single customer, CountryMark Cooperative LLP. During the first quarter of 2009, we placed into operation an oil offload facility in the Illinois Basin that we believe will enable us to diversify the purchasers of our oil in the future if we choose to do so. Additionally, we believe the growth in our Appalachian proved reserves will help us to minimize our future risks by diversifying our ratio of oil and gas sales as well as the quantity of purchasers.

6. COMMITMENTS AND CONTINGENCIES

Legal Reserves

At December 31, 2009, our Consolidated Balance Sheet included approximately $1.4 million in reserve for the legal matters referenced in Note 21—Litigation. At December 31, 2008, our Consolidated Balance Sheet included $327,000 in reserve for various legal proceedings. The accrual of reserves for legal matters is included in Accrued Expenses on the Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that we could incur additional loss, the amount of which is not currently estimable, in excess of the amounts currently accrued with respect to those matters in

which reserves have been established. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed current accruals by an amount that would have a material adverse effect on our consolidated financial position or results of operations, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

Drilling and Development

At December 31, 2009, we had two drilling commitments in our Appalachian Basin. The first commitment requires us to drill five natural gas wells and complete one natural gas well, which has already been started, by April, 2014. We estimate an average investment in each well to be $1.0 million for a total drilling commitment of $6.0 million. Our second drilling commitment requires that we build one well location and proceed with the drilling of one vertical test well, subject to rig availability, at an estimated cost of $1.0 million. If for any reason we do not meet this commitment we may be required to pay an amount equal to $100,000 upon the request of the landowner(s).

Leasing

At December 31, 2009, we had three installment payment commitments on mineral interests that were previously leased. The first commitment provides that we pay $350 per mineral acre for 5,722 acres, or a total commitment of $2.0 million, in 2012. The second commitment requires that we pay $250 per mineral acre for 5,761 acres, or $1.4 million, in each of the next three years for a total commitment of $4.2 million. The third commitment requires that we pay $350 per mineral acre for 762 acres, or $267,000, in each of the next three years for a total commitment of $801,000. We have recorded $1.7 million as a short-term liability in Accrued Expenses on the Consolidated Balance Sheets. The long-term portion of these payments is being recorded in Other Deposits and Liabilities on the Consolidated Balance Sheets.

Environmental

Due to the nature of the natural gas and oil business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews to identify changes in the environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate salaries and wages cost of employees who are expected to devote a significant amount of time directly to any remediation effort.

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Except for contingent liabilities associated with the enforcement action initiated by the U.S. EPA and the class action litigation filed in the U.S. District Court of the Southern District of Illinois relating to alleged H₂S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities.

Contract Wells

In March 2004, we purchased from Standard Steel, LLC certain contractual rights associated with various gas purchase contracts relating to 19 natural gas wells located in Westmoreland County, Pennsylvania. Under the terms of the contracts, we buy 100.0% of the production from these wells from third parties at contracted, fixed prices. The prices we pay may range from $1.10 per Mcf to 55.0% of the market price, plus a $0.10 per Mcf surcharge. There is no loss on these commitments. We have recorded the gross revenue and costs in the Consolidated Statements of Operations. We sell the natural gas extracted from these contract wells to parties unrelated to these natural gas wells and contracts.

Letters of Credit

We have posted $793,000, at December 31, 2009, in various letters of credit to secure our drilling and related operations.

Lease Commitments

At December 31, 2009 we have lease commitments for three different office locations. Rent expense has been recorded in General and Administrative expense as $364,000, $285,000 and $185,000 for the years ended December 31, 2009, 2008 and 2007, respectively. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands).


2010	$	452
2011		454
2012		456
2013		479
2014		—
Thereafter		—

Total	$	1,841

Other

In addition to the asset retirement obligation discussed in Note 2, Summary of Significant Accounting Policies, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. Such amounts, totaling $302,000, are included in Other Deposits and Liabilities at December 31, 2009 and December 31, 2008, respectively.

7. RELATED PARTY TRANSACTIONS

From September 2006 to May 2008, we leased an office building from Shaner Brothers, LLC, a Pennsylvania limited liability company (“Shaner Brothers”). Shaner Brothers is owned by Lance T. Shaner, our Chairman, and Shaner Family Partners Limited Partnership, a Pennsylvania limited partnership controlled by Mr. Shaner. On September 1, 2006, Shaner Brothers loaned $264,656 to Rex Operating to fund expenses relating to the construction of the interior portions the building. This loan was evidenced by an unsecured promissory note dated September 1, 2006 providing for interest on the unpaid principal sum at a rate of 7% per annum. The loan was required to be repaid in 60 consecutive equal monthly installments of principal and interest in the amount of $5,240.50. The promissory note was to mature on September 1, 2011, but could be prepaid in whole or in part at anytime, without premium or penalty. We repaid this loan in its entirety on July 30, 2007 with proceeds from our initial public offering. On December 26, 2007, we entered into a new office lease agreement with an unrelated third party and we relocated to the new office space in May 2008. Shaner Brothers thereafter terminated the office lease agreement, leased the office space to an unrelated third party and released us from any further obligations under the agreement.

Prior to April 2007, we received certain administrative services (such as information technology, human resources, benefit plan administration, payroll and tax services) from Shaner Solutions Limited Partnership, a Delaware limited partnership controlled by Mr. Shaner (“Shaner Solutions”), pursuant to an oral month-to-month agreement providing for a monthly fee of $15,000, plus reimbursement for reasonable out-of-pocket expenses. On April 10, 2007, we terminated our oral month-to-month administrative services agreement with Shaner Solutions. For the period covering January 1, 2007 to April 10, 2007, we paid Shaner Solutions $53,000 in relation to these services.

On April 10, 2007, we entered into an IT Consultation and Support Services Agreement (the “IT Agreement”), a Service Provider Agreement (the “Service Provider Agreement”) and a Tax Return Engagement Letter Agreement (the “Tax Services Agreement”) with Shaner Hotel Group Limited Partnership, a Delaware

limited partnership controlled by Mr. Shaner (“Shaner Hotel”). Pursuant to the IT Agreement, Shaner Hotel agreed to provide us with telecommunication, network administration, and information technology consultation services. Fees for the services provided under this agreement ranged from $55.00 to $125.00 per hour. Pursuant to the Service Provider Agreement, Shaner Hotel agreed to provide us with certain clerical and administrative support services in connection with the management and administration of our 401(k) retirement plan, payroll and employee health and welfare benefit plans. Fees for services provided under this agreement, ranged from $55.00 per hour to $95.00 per hour. Pursuant to the Tax Services Agreement, Shaner Hotel agreed to provide us with certain tax planning and tax return preparation services. Fees for the services provided under this agreement ranged from $100.00 to $155.00 per hour. All three agreements could be terminated by either party upon 90 days advance written notice. For services provided under these agreements, we paid $71,000 to Shaner Hotels for the year ending December 31, 2008 and $66,000 for the period covering April 10, 2007 to December 31, 2007. We elected to terminate the IT Agreement and Service Provider Agreement during 2008, but we did not terminate the Tax Services Agreement. For the year ending December 31, 2009, we paid Shaner Hotel approximately $5,000 for services provided under the Tax Services Agreement. We have engaged a third-party to provide us with tax planning and preparation services and expect to limit services provided under the Tax Services Agreement to only prior tax years. We believe that the amounts charged by Shaner Hotel were comparable to rates obtainable at an arm’s-length basis in the State College, Pennsylvania area for similar services.

We currently have an oral month-to-month agreement with Charlie Brown Air Corp., a New York corporation owned by Mr. Shaner (“Charlie Brown”), regarding the use of two airplanes owned by Charlie Brown. Under our agreement with Charlie Brown, we pay a monthly fee for the right to use the airplanes equal to our percentage (based upon the total number of hours of use of the airplanes by us) of the monthly fixed costs for the airplanes, plus a variable per hour flight rate that ranges from $400 to $2,500 per hour. The total monthly fixed costs for the airplanes are currently approximately $3,000 per month. For the years ended December 31, 2009, 2008 and 2007, we paid Charlie Brown $36,000, $74,000 and $202,000, respectively, in relation to these services. We believe the terms of this agreement are comparable to terms that could be obtained at an arms’ length basis in the State College, Pennsylvania area for similar private aircraft services.

On June 21, 2007, through our wholly owned subsidiary, Rex Operating, we obtained a 24.75% limited partnership interest in Charlie Brown II Limited Partnership, a Delaware limited partnership (“Charlie Brown II LP”), and a 25% membership interest in its general partner, L&B Air LLC, a Delaware limited liability company (“L&B Air”). The limited partnership was formed for the purpose of acquiring an Eclipse 500 Airplane, which it purchased for approximately $1,700,000. Shaner Hotel owned a 24.65% limited partnership interest in Charlie Brown II LP and a 25% membership interest in L&B Air, and Charlie Brown, an entity owned and controlled by Mr. Shaner, owned a 0.1% membership interest in Charlie Brown II LP. The remaining 49.50% limited partnership interest in Charlie Brown II LP and 50% interest in L&B Air were owned by an unrelated third party. On June 21, 2007, we made capital contributions to Charlie Brown II LP and L&B Air in the amount of $49,500 and $500, respectively. To fund these capital contributions, we borrowed $50,000 from Mr. Shaner. This loan was evidenced by a promissory note dated June 21, 2007 and bore interest at the rate of 7% per annum. The promissory note was payable upon the demand of Mr. Shaner and could be prepaid in whole or in part without penalty. We believe that the terms of this loan were comparable to terms that could be obtained at an arms’ length basis from unrelated lenders. We repaid this loan in its entirety on July 30, 2007 with proceeds from our initial public offering.

On June 21, 2007, Charlie Brown II LP and Charlie Brown entered into a First Amended and Restated Aircraft Joint Ownership and Management Agreement. Pursuant to this agreement, Charlie Brown agreed to provide certain aircraft management services, such as routine and scheduled maintenance, flight crew training, cleaning, inspections and flight operations and scheduling of the aircraft. In addition, Charlie Brown agreed to provide a flight crew for the operating of the aircraft and storage space in its hanger for storage of the aircraft. In exchange for these services, Charlie Brown II LP agreed to pay its proportionate share of Charlie Brown’s fixed costs, including crew, hanger and insurance costs, and a per hour flight charge to be determined by Charlie Brown consistent with current local market rates charged by similar flight operation companies.

On June 21, 2007, Charlie Brown II LP borrowed $1,530,000 from Graystone Bank. Proceeds from this loan were used to reimburse Mr. Shaner and an unrelated third party for a deposit they paid on behalf of Charlie Brown II LP in connection with the purchase of the Eclipse 500 airplane. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan requires payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II LP is required to make monthly payments of principal and interest utilizing an amortization period of 180 months. The loan to Charlie Brown II LP was originally guaranteed equally by Mr. Shaner and the unrelated third party; however, on February 27, 2009, Rex Energy Operating Corp. and Shaner Hotel each agreed with Graystone Bank to each guaranty up to twenty five percent of the principal balance of the loan and Mr. Shaner’s personal guaranty thereafter terminated. For the years ended December 31, 2009, 2008 and 2007, we paid Charlie Brown II LP $153,000, $69,000 and $9,000, respectively, for loan interest, services rendered and retainer fees.

On June 26, 2008, Charlie Brown II LP was converted to a Delaware limited liability company named Charlie Brown Air II, LLC, and on February 26, 2009, L & B Air merged into Charlie Brown Air II, LLC. Thereafter, our interests in Charlie Brown II LP and in L & B Air were converted to a twenty five percent (25%) membership interest in Charlie Brown Air II, LLC. In addition, the interests of Shaner Hotel and the unrelated third-party in Charlie Brown II LP and in L & B Air were converted to twenty five percent (25%) and fifty percent (50%) membership interests in Charlie Brown Air II, LLC, respectively. The business affairs of Charlie Brown Air II, LLC are managed by three managers, appointed by each of its three members. We have designated Benjamin W. Hulburt, our President and Chief Executive Officer, as the manager representing our membership interest. Actions of the company must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance with the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of the company, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown Air II, LLC, require the written consent of all managers. The consent of managers is also required before the company may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the company’s assets or sell the airplane owned by the company. In the event that the members are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the company.

Mr. Shaner is our Chairman and a significant stockholder of the company. Mr. Shaner’s ownership and association with Shaner Brothers, Shaner Solutions, Shaner Hotel, Charlie Brown, Charlie Brown Air II, LLC and us could create a conflict of interest between the interests of those entities and Mr. Shaner’s duties and obligations to us. The compensation for these arrangements and the purchase, leasing, financing, management and other arrangements between us and any Shaner affiliates may not be (to the extent permissible under applicable laws and regulations) a result of arm’s-length negotiations, and the relationships created by virtue of these arrangements may be subject to certain conflicts of interest. Our board of directors (with Mr. Shaner abstaining) performs a quarterly review of these contractual agreements, whether oral or written, and may continue, extend, amend or terminate any of these agreements.

Pursuant to the terms of a Participation and Exploration Agreement (the “PEA”) with Williams Production Company, LLC and Williams Production Appalachia, LLC (collectively, “Williams”) that was effective as of May 5, 2009, we agreed to form RW Gathering, LLC (“RW Gathering”), a Delaware limited liability company, to own any gas gathering assets which the parties agree to jointly construct in a project area located in Centre, Clearfield and Westmoreland Counties, Pennsylvania (the “Project Area”). The members of RW Gathering are Williams Production Appalachia, LLC and R.E. Gas Development, LLC (“R.E. Gas”), our wholly-owned subsidiary, with each member owning an equal interest in the company. R.E. Gas served as the manager of RW Gathering until December 31, 2009, and beginning on January 1, 2010, Williams Production Appalachia became the manager. We account for our interest in RW Gathering via the equity method of accounting. Our investment in RW Gathering totaled $840,000 as of December 31, 2009, and was recorded as Investment in RW Gathering on our Consolidated Balance Sheets. Our investment in RW Gathering includes existing gas gathering assets that were contributed and cash. Our investment was reduced by approximately $1,000 in losses incurred, primarily to

DD&A and bank fees, which are classified as Other Expense on our Consolidated and Combined Statements of Operations. As of December 31, 2009, there were no receivables of payables in relation to RW Gathering due to or from us.

On November 12, 2009, we entered into a limited liability agreement with Sand Hills Management, LLC (“Sand Hills”) to form Water Solutions Holdings, LLC (“Water Solutions Holdings”) for the purpose of acquiring, managing and operating water treatment, water disposal and water transportation facilities that are designed to treat, dispose or transport brine and other waste waters produced in oil and gas well development activities. The members of Water Solutions Holdings are Rex Energy Corporation, which owns an 80% membership interest, and Sand Hills, which owns a 20% membership interest. Pursuant to the limited liability company agreement, we contributed our 100% membership interest in Keystone Clearwater Solutions, LLC, which had an equity balance of approximately $403,000. Sand Hills contributed approximately $88,000 in capital assets and will contribute approximately $13,000 in cash. We have identified Water Solutions Holdings, LLC as a variable interest entity (for additional information, see Note 1, Basis of Presentation and Principles of Consolidation, to our Consolidated and Combined Financial Statements).

On December 21, 2009, our wholly owned subsidiary, R.E. Gas, and Stonehenge Energy Resources, L.P. (“Stonehenge”) formed Keystone Midstream Services, LLC (“Keystone Midstream”), a midstream joint venture focused on building, operating and owning a high pressure gathering system and cryogenic gas processing plant in Butler County, Pennsylvania. R.E. Gas owns a 40% membership interest in Keystone Midstream and the remaining 60% membership interest is owned by Stonehenge. Pursuant to the terms of the limited liability company agreement and contribution agreement entered into by R.E. Gas and Stonehenge, R.E. Gas contributed to Keystone Midstream its 16.3% undivided interest in a skid-mounted cryogenic natural gas processing plant (the “Gas Processing Plant”), valued at $740,000, and an option to purchase R.E. Gas’s existing gas gathering system in Butler County, Pennsylvania, valued at $1.8 million. Stonehenge contributed to Keystone Midstream its 83.7% undivided interest in the Gas Processing Plant valued at $3.8 million, of which approximately $3.3 million had been paid for as of December 31, 2009. During 2009, we provided contract services to Keystone Midstream for environmental engineering and designing. We recorded income for these services of approximately $68,000 as Other Income (Expense) on our Consolidated Statements of Operations. We have identified Keystone Midstream to be a variable interest entity (for additional information, see Note 1, Basis of Presentation and Principles of Consolidation, to our Consolidated and Combined Financial Statements).

8. LONG-TERM DEBT

We maintain a revolving credit facility evidenced by the Credit Agreement, dated September 28, 2007, with KeyBank, as Administrative Agent; BNP Paribas, as Syndication Agent; Sovereign Bank, as Documentation Agent; and lenders from time to time parties thereto (as amended from time to time, the “Senior Credit Facility”). Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. The borrowing base under the Senior Credit Facility is currently $80 million; however, the revolving credit facility may be increased up to $200 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. The Senior Credit Facility provides that

the borrowing base will be re-determined semi-annually by the lenders, in good faith, based on, among other things, reports regarding our oil and gas reserves attributable to our oil and gas properties, together with a projection of related production and future net income, taxes, operating expenses and capital expenditures. Any re-determined borrowing base will become effective on the subsequent April 1 and October 1. We may, or the Administrative Agent at the direction of a majority of the lenders may, each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In addition, we may request interim borrowing base re-determinations upon our proposed acquisition of proved developed producing oil and gas reserves with a purchase price for such reserves greater than 10% of the then borrowing base.

Loans made under the Senior Credit Facility mature on September 28, 2012, and in certain circumstances, we will be required to prepay the loans. Borrowings under the Senior Credit Facility bear interest, at our election, at the Adjusted LIBO Rate or the Alternative Base Rate (as defined below) plus, in each case an applicable per annum margin. The applicable per annum margin is determined based upon our total borrowing base utilization percentage in accordance with a pricing grid. The applicable per annum margin ranges from 1.75% to 2.5% for Eurodollar loans and .5% to 1.25% for ABR loans. The Adjusted Base Rate is equal to the greater of: (i) KeyBank’s announced prime rate; (ii) the federal funds effective rate from time to time plus ¹/2 of 1%; and (iii) LIBO Rate plus 1.25%. Our commitment fee is also dependent on our total borrowing base utilization percentage and is determined based upon an applicable per annum margin which ranges from .375% to .50%.

Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million and 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate.

The Senior Credit Facility contains covenants that restrict our ability to, among other things, materially change our business; approve and distribute dividends; enter into transactions with affiliates; create or acquire additional subsidiaries; incur indebtedness; sell assets; make loans to others; make investments; enter into mergers; incur liens; and enter into agreements regarding swap and other derivative transactions (see Note 9 for further information on our derivative instruments). The Senior Credit Facility also requires we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total debt to EBITDAX. Borrowings under the Senior Credit Facility have been used to finance our working capital needs and for general corporate purposes in the ordinary course of business, including the exploration, acquisition and development of oil and gas properties. Obligations under the Senior Credit Facility are secured by mortgages on the oil and gas properties of our subsidiaries located in the states of Illinois and Indiana. We are required to maintain liens covering our oil and gas properties representing at least 80% of our total value of all oil and gas properties.

We pledge our oil and natural gas properties as collateral under the Senior Credit Facility and are subject to certain financial covenants. The first of such covenants states that as of the last day of any fiscal quarter, our ratio of EBITDAX for the period of four fiscal quarters ending on such day to interest expense for such period is to be less than 3.0 to 1.0. Additionally, as of the last day of any fiscal quarter our ratio of total debt to EBITDAX for the period of four fiscal quarters ending on such day is to be greater than 4.0 to 1.0. The last covenant states that as of the last day of any fiscal quarter, our ratio of consolidated current assets as of such day to consolidated current liabilities as of such day is to be less than 1.0 to 1.0. As of December 31, 2009, we were in compliance with all of our debt covenants.

In addition to our Senior Credit Facility, we may, from time to time in the normal course of business, finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and lines of credit consists of the following at December 31, 2009 and 2008:


	December 31, 2009 ($ in Thousands)			December 31, 2008 ($ in Thousands)
Senior-Secured Lines of Credit	$	23,000		$	15,000
Other Loans and Notes Payable		366			—

Total Debts		23,366			15,000
Less Current Portion of Long-Term Debt		(317	)		—

Total Long-Term Debts	$	23,049		$	15,000

The terms of the Senior Credit Facility require that we make monthly payment of interest on the outstanding balance of loans made under the agreement. Loans made under the Senior Credit Facility mature on September 28, 2012, and in certain circumstances, we will be required to prepay the loans.

The following is the principal maturity schedule for debt outstanding as of December 31, 2009 ($ in thousands):


	Year Ended December 31,
2010	$	317
2011		28
2012		23,021
2013		—
2014		—
Thereafter		—

Total	$	23,366

9. FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVE INSTRUMENTS

Our results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we enter into oil and natural gas commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparty. We do not enter into these arrangements for speculative trading purposes. As of December 31, 2009, 2008 and 2007, our oil and natural gas derivative commodity instruments consisted of fixed rate swap contracts and collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as other income or expense.

Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a calculation period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a calculation period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price.

We enter into the majority of our derivative arrangements with one counterparty and have a netting agreement in place with this counterparty. We do not obtain collateral to support the agreements, but we believe

our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 5, Concentrations of Credit Risk, to our Consolidated and Combined Financial Statements.

None of our derivatives are designated for hedge accounting but are, to a degree, an economic offset to our oil and natural gas price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all unrealized and realized gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Income (Expense).

We received net cash receipts of $10.4 million the year ended December 31, 2009. We made net payments of approximately $16.2 million and $6.2 million under these commodity derivative instruments during years ended December 31, 2008 and 2007, respectively. During the first quarter of 2009, we redeemed our oil hedges related to production in 2011 for net cash proceeds of approximately $4.6 million. Unrealized gains and losses associated with our commodity derivative instruments from continuing operations amounted to a loss of $17.1 million, a gain of $43.7 million and a loss of $26.3 million for the years ended December 31, 2009, 2008 and 2007, respectively.

The following table summarizes the location and amounts of gains and losses on derivative instruments, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007 ($ in thousands):


	Year Ended December 31, 2009
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total
*Crude Oil*
Reclassification of settled contracts included in prior periods mark-to-market adjustment	$	—		$	(10,331	)	$	(10,331	)
Mark-to-market fair value adjustments		—			(8,114	)		(8,114	)
Settlement of contracts(a)		7,198			—			7,198

Crude Oil Total		7,198			(18,445	)		(11,247	)


*Natural Gas*
Reclassification of settled contracts included in prior periods mark-to-market adjustment		—			(1,091	)		(1,091	)
Mark-to-market fair value adjustments		—			1,518			1,518
Settlement of contracts(a)		3,216			—			3,216

Natural Gas Total		3,216			427			3,643


*Interest Rate*
Reclassification of settled contracts included in prior periods mark-to-market adjustment		—			611			611
Mark-to-market fair value adjustments		—			(151	)		(151	)
Settlement of contracts(a)		(769	)		—			(769	)

Interest Rate Total		(769	)		460			(309	)

Gain (Loss) on Derivatives, Net	$	9,645		$	(17,558	)	$	(7,913	)

(a)	These amounts represent the realized gains and losses on settled derivatives, which before settlement are included in the mark-to-market fair value adjustments.


	Year Ended December 31, 2008
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total
*Crude Oil*
Reclassification of settled contracts included in prior periods mark-to-market adjustment	$	—		$	10,863		$	10,863
Mark-to-market fair value adjustments		—			30,584			30,584
Settlement of contracts(a)		(15,613	)		—			(15,613	)

Crude Oil Total		(15,613	)		41,447			25,834


*Natural Gas*
Reclassification of settled contracts included in prior periods mark-to-market adjustment		—			9			9
Mark-to-market fair value adjustments		—			3,461			3,461
Settlement of contracts(a)		(554	)		—			(554	)

Natural Gas Total		(554	)		3,470			2,916


*Interest Rate*
Reclassification of settled contracts included in prior periods mark-to-market adjustment		—			—			—
Mark-to-market fair value adjustments		—			(1,171	)		(1,171	)
Settlement of contracts(a)		(251	)		—			(251	)

Interest Rate Total		(251	)		(1,171	)		(1,422	)

Gain (Loss) on Derivatives, Net	$	(16,418	)	$	43,746		$	27,328

(a)	These amounts represent the realized gains and losses on settled derivatives, which before settlement are included in the mark-to-market fair value adjustments.


	Year Ended December 31, 2007
	Realized Gains (Losses)			Unrealized Gains (Losses)			Total
*Crude Oil*
Reclassification of settled contracts included in prior periods mark-to-market adjustment	$	—		$	2,609		$	2,609
Mark-to-market fair value adjustments		—			(27,874	)		(27,874	)
Settlement of contracts(a)		(6,829	)		—			(6,829	)

Crude Oil Total		(6,829	)		(25,265	)		(32,094	)


*Natural Gas*
Reclassification of settled contracts included in prior periods mark-to-market adjustment		—			(905	)		(905	)
Mark-to-market fair value adjustments		—			(80	)		(80	)
Settlement of contracts(a)		630			—			630

Natural Gas Total		630			(985	)		(355	)


*Interest Rate*
Reclassification of settled contracts included in prior periods mark-to-market adjustment		—			—			—
Mark-to-market fair value adjustments		—			—			—
Settlement of contracts(a)		20			—			20

Interest Rate Total		20			—			20

Gain (Loss) on Derivatives, Net	$	(6,179	)	$	(26,250	)	$	(32,429	)

(a)	These amounts represent the realized gains and losses on settled derivatives, which before settlement are included in the mark-to-market fair value adjustments.

As of December 31, 2009, we had entered into an interest rate swap derivative instrument which hedged our interest rate risk associated with changes in LIBOR on $20.0 million of notional value. We use the interest rate swap agreement to manage the risk associated with interest payments on amounts outstanding from variable rate borrowings under our Senior Credit Facility. Under our interest rate swap agreement, we agree to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to receive in return, a specified variable rate of interest times the same notional principal amount. The interest rate under the swap is 4.15% and the agreement expires in November 2010. The fair value of the swap at December 31, 2009 was a liability of $0.7 million, a decrease of $0.5 million from the year ended December 31, 2008 based on current LIBOR quotes. We have accounted for the interest rate swap by recording the unrealized and realized gains in Gain (Loss) on Derivatives, Net on our Consolidated Statements of Operations.

Our derivative instruments are recorded on the balance sheet as either an asset, or a liability, measured at its fair value. The fair value associated with our derivative instruments from continuing operations was a liability of approximately $3.3 million and an asset of $14.2 million at December 31 2009 and 2008, respectively. The fair value is based on the valuation methodologies of our counterparties. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2009 consisted of:


Period	Contract Type	Volume	Average Derivative Price	Fair Market Value ($ in Thousands)
Oil
2010	Swaps	180,000 Bbls	$62.20	$	(3,615	)
2010	Collars	408,000 Bbls	$62.94 – 86.85	$	(2,169	)
2011	Collars	228,000 Bbls	$63.42 – 108.87	$	(400	)
2011	Collars	72,000 Bbls	$60.00 – 127.00	$	5

	Total	888,000 Bbls		$	(6,179	)
Natural Gas
2010	Swaps	120,000 Mcf	$6.00	$	25
2010	Collars	2,160,000 Mcf	$6.31 – 9.07	$	1,900
2011	Collars	1,800,000 Mcf	$6.47 – 10.47	$	1,560
2012	Collars	600,000 Mcf	$5.60 – 7.86	$	84

	Total	4,680,000 Mcf		$	3,569

The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of December 31, 2009 and December 31, 2008 is summarized below ($ in thousands).


	December 31, 2009			December 31, 2008
Short-Term Derivative Assets:
Crude Oil—Swaps	$	—		$	1,821
Crude Oil—Collars		178			5,241
Natural Gas—Swaps		25			—
Natural Gas—Collars		1,921			1,091

Total Short—Term Derivative Assets	$	2,124		$	8,153

Long-Term Derivative Assets:
Crude Oil—Swaps	$	—		$	—
Crude Oil—Collars		9			5,511
Natural Gas—Swaps		—			—
Natural Gas—Collars		1,664			2,050

Total Long—Term Derivative Assets	$	1,673		$	7,561

Total Derivative Assets	$	3,797		$	15,714

Short-Term Derivative Liabilities:
Crude Oil—Swaps	$	(3,615	)	$	—
Crude Oil—Collars		(2,346	)		—
Natural Gas—Swaps		—			—
Natural Gas—Collars		(20	)		—
Interest Rate—Swap		(711	)		—

Total Short—Term Derivative Liabilities	$	(6,692	)	$	—

Long-Term Derivative Liabilities:
Crude Oil—Swaps	$	—		$	(303	)
Crude Oil—Collars		(405	)		(2	)
Natural Gas—Swaps		—			—
Natural Gas—Collars		(21	)		—
Interest Rate—Swap		—			(1,171	)

Total Long—Term Derivative Liabilities	$	(426	)	$	(1,476	)

Total Derivative Liabilities	$	(7,118	)	$	(1,476	)

Effective January 1, 2008, we adopted FASB ASC 820-10, which among other things, requires enhanced disclosures about assets and liabilities carried at fair value. As defined in FASB ASC 820-10, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. FASB ASC 820-10 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy defined by FASB ASC 820-10 are as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

100

Level 2—Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table presents the fair value hierarchy table for assets and liabilities measured at fair value ($ in thousands):


	Total Carrying Value as of December 31, 2009			Fair Value Measurements at December 31, 2009 Using:
	Total Carrying Value as of December 31, 2009			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Derivatives—commodity swaps and collars	$	(2,610	)	$	—	$	(2,610	)	$	—
—interest rate swaps	$	(711	)	$	—	$	(711	)	$	—
Asset Retirement Obligations	$	(16,143	)	$	—	$	—		$	(16,143	)

Our derivative commodity swaps and collars and interest rate swaps are valued by a third-party using valuation models that are primarily industry-standard models that consider various inputs including: quoted forward prices; time value; volatility factors; and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative commodity swaps and collars and interest rate swaps are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments.

Asset Retirement Obligations

We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Summary of Significant Accounting Policies, to our Consolidated and Combined Financial Statements for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances which represent the entirety of our Level 3 fair value measurements.

101

10. INCOME TAXES

We recognize deferred tax liabilities and assets for the expected future tax consequences of events that may be recognized in our financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial carrying amounts and tax bases of assets and liabilities using enacted tax rates. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. We recognized deferred tax assets and liabilities upon the consummation of the Reorganization Transactions and acquisition of noncontrolling interests. Before these events, the Predecessor Companies were pass-through entities that did not pay income taxes and did not reflect deferred tax assets and liabilities.

The Predecessor Companies were treated as partnerships or subchapter S corporations for federal and state income tax purposes. Accordingly, income taxes were not reflected in the combined financial statements because the resulting profit or loss was included in the income tax returns of the individual stockholders, members or partners. Accordingly, we did not derecognize any tax benefits, nor recognize any interest expense or penalties on unrecognized tax benefits as of the date of adoption. Income tax expense has been provided for on our Consolidated and Combined Statement of Operations prospectively for periods after August 1, 2007.

All information in the tables below includes results from continuing operations and discontinued operations.


	Year Ended December 31, 2009		Year Ended December 31, 2008
Current:
Federal	$	—	$	—
State		—		—
Deferred:
Federal		9,626		9,819
State		1,088		1,084

Total Income Tax Benefit	$	10,714	$	10,903

A reconciliation of income tax expense using the statutory U.S. income tax rate compared with actual income tax expense is as follows:


	Year Ended December 31, 2009			Year Ended December 31, 2008
Net loss before noncontrolling interests and income taxes	$	(26,947	)	$	(59,287	)
Statutory U.S. income tax rate		35	%		35	%

Tax benefit recognized using statutory U.S. income tax rate	$	9,431		$	20,750
Change in estimated future state rate		(301	)		666
Permanent differences		(7	)		(11,825	)
Other		230			228

Adjusted federal income tax benefit	$	9,353		$	9,819
State income tax benefit		1,361			1,084

Total income tax benefit	$	10,714		$	10,903

Effective income tax rate		39.8	%		18.4	%

(a)

At December 31, 2008, we reclassified approximately $298,000 of net income before noncontrolling interests and income taxes to accounts payable. As a result of the effective date of the sale of our Southwest Region properties being determined as October 1, 2008, this amount represents the income for the three month period ending December 31, 2008, that is due to the purchaser of our Southwest Region properties. This amount is not recognizable as income for book purposes; however it is required to be recognized as income for tax purposes.

102

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax liabilities (assets) are comprised of the following at December 31, 2009 and 2008.


	December 31, 2009			December 31, 2008
Tax effects of temporary differences for:
Current:
Assets:
Unrealized loss on derivatives	$	1,830		$	—
Other		997			—

Total current deferred tax assets		2,827			—

Liabilities:
Unrealized gain on derivatives		—			(3,100	)
Other		—			315

Total current deferred tax liabilities		—			(2,785	)


Long-Term:
Assets:
Asset retirement obligation		6,465			2,636
Non-Cash Compensation Plans		1,480			—
Net operating loss carryforward		6,750			3,177
Other		157			1,678

Total long-term deferred tax assets		14,852			7,491

Liabilities:
Deferred gain on early hedge settlements		(1,831	)		—
Unrealized gain on derivatives		—			(2,180	)
Book basis of oil and gas properties in excess of tax basis		(19,915	)		(17,306	)

Net long-term deferred tax liability	$	(6,894	)	$	(11,995	)

Management continuously evaluates the facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets. These deferred tax assets consist primarily of net operating losses and deductible temporary differences. For the year ended December 31, 2009, management determined, based on positive and negative evidence examined and anticipated future taxable income, that it is now more than likely than not that these deferred tax assets will likely be realized in the future. Accordingly, we determined that it is appropriate to present our deferred tax assets without a valuation allowance.

Our management will continue, in future periods, to assess the likely realization of the deferred tax assets. The valuation allowance may change based on future changes in circumstances.

At December 31, 2009, we had available unused net operating loss carryforwards that may be applied against future taxable income that expire as follows ($ in thousands):


Year of Expiration	Net Operating Loss Carryforwards
2027	$	3,793
2028		12,869
2029		193
Thereafter		—

Total	$	16,855

103

Effective August 1, 2007, we adopted FASB ASC 740-10, which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with FASB ASC 740. FASB ASC 740-10 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Our practice is to recognize interest related to income tax expense in Interest Expense and penalties in General and Administrative expense. We did not have any accrued interest or penalties as of December 31, 2009 and 2008.

We also adopted FASB ASC 740-10-25-9 as of August 1, 2007. FASB ASC 740-10-25-9 provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal and it is remote that the taxing authority would reexamine the tax position in the future.

The adoption of FASB ASC 740-10 and FASB ASC 740-10-25-9 had no significant effect on our financial position, results of operations or cash flows.

FASB ASC 740-10 sets forth a two-step process for evaluating tax positions. The first step is financial statement recognition of the tax position based on whether it is more likely than not that the position will be sustained upon examination by taxing authorities and resolution through related appeals or litigation, based on the technical merits of the case. FASB ASC 740-10 mandates certain assumptions in applying the more likely than not judgment, including the presupposition of an examination where the taxing authorities are fully informed of all relevant information for evaluation of the tax position. In other words, FASB ASC 740-10 precludes factoring the likelihood of a tax examination into the evaluation of the outcome so that the evaluation is to focus solely on the technical merits of the position.

Our management has concluded that, as of December 31, 2009, we have not taken any tax positions that would require disclosure as “unrecognized positions” and that no liability balance is required to offset any unsustainable positions.

We file a consolidated federal income tax return and separate or consolidated state income tax returns in the United States Federal jurisdiction and in many state jurisdictions. We are subject to U.S. Federal income tax examinations and to various state tax examinations for periods after August 1, 2007.

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11. EARNINGS PER COMMON SHARE

Basic income per common share is calculated based on the weighted average number of common shares outstanding at the end of the period. Diluted income per common share includes the speculative exercise of stock options and SARs, given that the hypothetical effect is not anti-dilutive. Due to our net loss from continuing operations for the year ended December 31, 2009, we excluded all 873,837 of outstanding stock options and 73,500 SARs because the effect would have been anti-dilutive to the computations. Due to our net loss from continuing operations for the year ended December 31, 2008, we excluded all 993,700 of outstanding stock options and 73,500 SARs because the effect would have been anti-dilutive to the computations. Due to our net loss from continuing operations for the year ended December 31, 2007, we excluded all 790,000 of outstanding stock options because the effect would have been anti-dilutive to the computation. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share data):


	Year Ended December 31, 2009			Year Ended December 31, 2008			Year Ended December 31, 2007
Numerator:
Net Income (Loss) From Continuing Operations(1)	$	(16,556	)	$	(40,978	)	$	(11,304	)
Net Income (Loss) From Discontinued Operations(1)		323			(7,704	)		664

Net Income (Loss)	$	(16,233	)	$	(48,682	)	$	(10,640	)


Denominator:
Weighted Average Common Shares Outstanding—Basic		36,806			34,595			30,795
Effect of Dilutive Securities:
Employee Stock Options and SARs		—			—			—

Weighted Average Common Shares Outstanding—Diluted		36,806			34,595			30,795


Earnings per Common Share(2)
Basic—Net Income (Loss) From Continuing Operations	$	(0.45	)	$	(1.18	)	$	(0.37	)
—Net Income (Loss) From Discontinued Operations		0.01			(0.22	)		0.02

—Net Income (Loss)	$	(0.44	)	$	(1.40	)	$	(0.35	)

Diluted—Net Income (Loss) From Continuing Operations	$	(0.45	)	$	(1.18	)	$	(0.37	)
—Net Income (Loss) From Discontinued Operations		0.01			(0.22	)		0.02

—Net Income (Loss)	$	(0.44	)	$	(1.40	)	$	(0.35	)

(1)	Earnings per common share for 2007 represents the results for the 5-month period ended December 31, 2007.

(2)	All earnings per share amounts are attributable to Rex common shareholders.

12. CAPITAL STOCK

Currently, our common stock is traded on the NASDAQ Global Market under the trading symbol “REXX”. We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. In July 2007, we completed our initial public offering of 9,600,000 shares of common stock at $11.00 per share. In May 2008, we completed a public offering of 5,775,000 shares of common stock at an offering price of $20.75 per share. As of December 31, 2009, we had 36,817,812 shares of common stock outstanding.

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13. MAJOR CUSTOMERS

PennTex Illinois, PennTex Resources, Rex I, LLC. and Rex IV sold the majority of their oil production in the Indiana and Illinois fields to CountryMark Cooperative LLP. The total amount of oil sold to CountryMark Cooperative, LLP in 2009, 2008 and 2007 was approximately $37.2 million, $74.0 million and $52.3 million, respectively. These sales represent 77%, 88% and 90%, respectively, of total oil and natural gas sales.

14. EMPLOYEE BENEFIT AND EQUITY PLANS

401(k) Plan

We sponsor a 401(k) Plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan are discretionary. Our contributions to the plan were approximately $144,000, $272,000 and $204,000 for the years ended December 31, 2009, 2008 and 2007, respectively. We paid approximately $8,000 of expenses per year on behalf of the 401(k) plan for the years ended December 31, 2009, 2008 and 2007, respectively.

Equity Plans

We recognize all share-based payments to employees, including grants of employee stock options, in the income statement based on their grant-date fair values, using prescribed option-pricing models. The fair value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period. Prior to August 1, 2007, we did not have any share-based payments to employees or directors. Although we have not yet recognized any tax benefits, we would report any benefits of tax deductions in excess of recognized compensation as a financing cash flow, rather than as an operating cash flow.

2007 Long-Term Incentive Plan

We have granted stock options, stock appreciation rights and restricted stock awards to various employees and non-employee directors under the terms of our 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the compensation committee of our board of directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are selecting participants to receive awards, determining the form, amount and other terms and conditions of awards, interpreting the provisions of the Plan or any award agreement and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees, intend to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes.

All awards granted under the Plan have been issued at the prevailing market price at the time of the grant. All outstanding stock options have been awarded with five or ten year expiration at an exercise price equal to our closing price on the NASDAQ Global Market on the day of the award. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively.

Stock Options

During the year ended December 31, 2009, the Compensation Committee awarded nonqualified options to purchase a total of 68,888 shares of our common stock to one employee and four non-employee directors. During the year ended December 31, 2008, the Compensation Committee awarded nonqualified options to purchase a total of 516,200 shares of our common stock to 23 employees and four non-employee directors. The nonqualified

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stock options granted to our employees have an exercise price equal to the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable on the third anniversary of the grant date, provided that the option holder remains our employee until that date. The nonqualified stock options granted to our non-employee directors have an exercise price equal to the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable in one-third increments on the first, second and third year anniversaries of the date of grant. All options also provide that all unvested options vest and become immediately exercisable upon a “change in control” of us; as such term is defined in the Plan. During fiscal year 2009, with the approval of our Compensation Committee, we modified the terms of certain stock option award agreements of three former employees located in our Southwest Region to partially vest options previously granted to such individuals. The options were partially vested pursuant to the terms of severance agreements entered into with the former employees as a result of the termination of their employment following the sale of our Southwest Region assets and the closing of our Midland, Texas office in March 2009. As modified, the options partially vested and became exercisable with respect to a total of 58,749 shares of our common stock.

Stock options represent the right to purchase shares of stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, shall again be available for the purposes of the Plan. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the Plan or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the Plan.

A summary of the stock option activity is as follows:


	Number of Shares		Weighted Average Exercised Price
Options outstanding, December 31, 2006	—		$	—
Granted	800,000			9.91
Exercised	—			—
Cancelled	(10,000	)		9.99

Options outstanding, December 31, 2007	790,000		$	9.90
Granted	516,200			21.50
Exercised	—			—
Cancelled/Forfeited	(312,500	)		16.86

Options outstanding, December 31, 2008	993,700		$	13.81
Granted	68,888			4.84
Exercised	—			—
Cancelled/Forfeited	(188,751	)		12.06

Options outstanding, December 31, 2009	873,837		$	13.41

Stock-based compensation expense relating to stock options for the years ended December 31, 2009, 2008 and 2007 totaled $1.0 million, $3.0 million and $0.2 million, respectively. The expense related to stock option grants was recorded on our Consolidated and Combined Statements of Operations under the heading of General and Administrative expense.

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The total number of options granted in 2009 and 2008 were 68,888 and 516,200, respectively. The fair value of each option grant is estimated on the date of the grant using the Black-Scholes option-pricing model with the following assumptions:


	Year Ended December 31,
	2009		2008		2007
Expected dividend yield	—		—		—
Expected stock price volatility	72	%	46	%	45	%
Risk-free interest rate	1.87	%	3.21	%	4.10	%
Expected life of options (years)	4 – 6.5		4 – 6.5		6.5

The dividend yield of zero is based on the fact that we have never paid cash dividends on common stock and have no present intention of doing so. Our expected historical volatility factor was determined by assessing the common stock trading history of eight publicly-traded oil and gas companies that we determined to be similar to us in ways such as their operating strategy, capital structure, production mix and volume and asset size. The risk-free interest rate was determined by interpolating the average yield on a U.S. Treasury bond for a period approximately equal to the expected average life of the options. The average expected life has been determined using the “simplified method” in which the average expected life of the option is equal to the average of the term of the option and the vesting period. We elected to use the simplified method for determining the average expected life because we do not have a history on which to base estimates for the term to exercise of our granted stock options. We used an estimated forfeiture rate of 32% in 2009 for calculating stock-based compensation expense related to stock options and this rate is based on historical experience.

Based on the above assumptions, the weighted average estimated fair value of options granted during the years ended December 31, 2009, 2008 and 2007 was $3.03 per share, $9.35 per share and $4.99 per share, respectively. The weighted average exercise price of options granted during 2009, 2008 and 2007 was $4.84, $21.50 and $9.91 per share, respectively.

A summary of the status of our issued and outstanding stock options as of December 31, 2009 is as follows:


	Outstanding				Exercisable
Exercise Price	Number Outstanding at 12/31/09	Weighted- Average Remaining Contractual Life (Years)	Weighted- Average Exercise Price		Number Exercisable at 12/31/09	Weighted- Average Exercise Price
$9.50	125,000	7.85	$	9.50	83,334	$	9.50
9.99	363,749	7.85		9.99	58,749		9.99
13.56	33,200	8.14		13.56	—		—
22.34	50,000	8.30		22.34	12,000		22.34
23.00	75,000	8.35		23.00	—		—
23.88	75,000	3.39		23.88	—		—
23.28	10,000	3.53		23.28	—		—
19.92	26,000	3.62		19.92	—		—
21.10	30,000	3.65		21.10	—		—
5.60	17,000	3.87		5.60	—		—
3.24	7,500	4.04		3.24	—		—
5.04	61,388	9.35		5.04	—		—

Total	873,837	7.22	$	13.41	154,083	$	10.69

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at December 31, 2009 were 6.87 years and $0, respectively. The weighted average remaining contractual term

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and the aggregate intrinsic value for options exercisable at December 31, 2009 were 7.90 years and $0, respectively. As of December 31, 2009, unrecognized compensation expense related to stock options totaled approximately $1.8 million, which will be recognized over a weighted average period of 1.17 years.

Stock Appreciation Rights

During the year ended December 31, 2008, the Compensation Committee awarded 109,500 stock appreciation rights (“SARs”) to five employees and there were no awards in 2009. SARs represent the right to receive cash or shares of common stock in the future equivalent to the difference between the fair market value at the time of exercise and the strike price. The SARs have an exercise price equal to $13.56, the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vest and become exercisable on the third anniversary of the grant date, provided that the holder remains our employee until that date. The SARs also provide that all unvested SARs vest and become immediately exercisable upon a “change in control” of us, as such term is defined in the Plan. The outstanding SARs issued as of December 31, 2009 may only be exercised for cash settlement. As of December 31, 2009, unrecognized compensation expense related to SARs totaled approximately $201,000.


		Outstanding			Exercisable
Strike Price	Number of SARs Granted	SARs Forfeited or Cancelled	SARs Outstanding	Weighted- Average Remaining Contractual Life (Years)	Weighted- Average Strike Price		SARs	Weighted- Average Exercise Price
$13.56	109,500	36,000	73,500	8.13	$	13.56	—	—

Total	109,500	36,000	73,500	8.13	$	13.56	—	—

Restricted Stock Awards

During the year ended December 31, 2009, the Compensation Committee issued 261,850 shares of restricted common stock to 15 employees, with all restrictions on transfer associated with such shares scheduled to terminate in February 2012. During the year ended December 31, 2008, the Compensation Committee issued 20,000 shares of restricted common stock to one employee, with all restrictions on transfer associated with such shares scheduled to terminate in May 2013. The restricted common stock is valued at the closing price of our common stock on the NASDAQ Global Market on the date of the grant. Restrictions on the transfer associated with vesting schedules are determined by the Compensation Committee on an individual award basis. The restrictions on the stock lapse immediately upon a “change in control” of us, as such term is defined in the Plan. Compensation expense associated with the restricted stock award is recognized on a straight-line basis over the vesting period. As of December 31, 2009, total unrecognized compensation cost related to the restricted common stock grant was approximately $608,000.

A summary of the restricted stock activity for the years ended December 31, 2009 and 2008 is as follows:


	Number of Shares		Weighted Average Grant Date Fair Value
Restricted stock awards, as of January 1, 2008	—		$	—
Awards	20,000			23.00
Forfeitures	—			—

Restricted stock awards, as of December 31, 2008	20,000		$	23.00
Awards	261,850			2.05
Forfeitures	(33,750	)		2.05

Restricted stock awards, as of December 31, 2009	248,100		$	3.74

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15. SUSPENDED EXPLORATORY WELL COSTS

We capitalize the costs of exploratory wells if a well finds a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

The following table reflects the net change in capitalized exploratory well costs, excluding those related to our Southwest Region properties which are currently classified as Held for Sale on our Consolidated Balance Sheets as of December 31, 2008 and 2007, for the years ended December 31, 2009, 2008 and 2007 ($ in thousands):


	2009			2008			2007
Beginning Balance at January 1,	$	3,716		$	5,877		$	2,538
Additions to capitalized exploratory well costs pending the determination of proved reserves		4,130			2,324			4,577
Divested Wells		—			(4,485	)		—
Reclassification of wells, facilities, and equipment based on the determination of proved reserves		—			—			—
Capitalized exploratory well costs charged to expense		—			—			(1,238	)

Ending Balance at December 31,		7,846			3,716			5,877
Less exploratory well costs that have been capitalized for a period of one year or less		(4,130	)		(2,310	)		(4,438	)

Capitalized exploratory well costs for a period of greater than one year	$	3,716		$	1,406		$	1,439
Number of projects that have exploratory well costs capitalized for a period of more than one year		3			1			1

The $3.7 million in capitalized well costs that have been capitalized for a period greater than one year relate to three projects, one in our Illinois Basin and two in our Appalachian Basin. The costs related to our Illinois Basin are for the ASP project and were incurred over the last three years. Proved reserve quantities for tertiary recovery projects, such as the ASP project, typically take a longer period of time to evaluate than conventional operations due to their capital intensive nature and longer lead time of producing results. We are continuously undergoing an analysis of various stimulation techniques, with the assistance of an outside third-party consultant, to determine if economic quantities of crude oil can be produced from this project. The projects in the Appalachian Basin relate to two wells which have been drilled, or are in the process of being drilled, in our Clearfield County, Pennsylvania project area which were incurred during 2008. The first of these wells has been drilled, but is not yet active, due to the lack of a current sales outlet. This well is continuously tested and monitored and has displayed, in our opinion, the ability to produce economic quantities of natural gas when a sales outlet is in place. The second well, which is in close proximity of the first well, has not yet been completed due to the lack of a current sales outlet. However, it is believed that when this well is completed it will perform similar to the first well and be capable of producing economic quantities once a sales outlet is in place. We do intend to continue to drill wells in this area, at which time a sales outlet will be constructed and our two previously discussed wells will be completed and activated.

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16. COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION AND DEVELOPMENT ACTIVITIES (UNAUDITED)

Costs incurred in oil and natural gas property acquisitions and development are presented below:


	2009		2008		2007
Consolidated Entities:
Acquisition of Properties
Proved	$	39	$	4,950	$	1,090
Unproved		17,949		57,224		4,141
Exploration Costs		6,210		5,571		5,676
Development Costs(1)		26,921		76,109		24,180

Total	$	51,119	$	143,854	$	35,087

Share of Equity Method Investments:
Acquisition of Properties
Proved	$	—	$	—	$	—
Unproved		296		—		—
Exploration Costs		—		—		—
Development Costs(1)		1,241		—		—

Total	$	1,537	$	—	$	—

(1)	Includes Depreciation expense for support equipment and facilities.

Property acquisition costs include costs incurred to purchase, lease or otherwise acquire property as well as capitalized future abandonment costs. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells and to provide facilities to extract, treat and gather natural gas and oil.

17. OIL AND NATURAL GAS CAPITALIZED COSTS (UNAUDITED)

Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below.


	2009			2008
Consolidated Entities:
Proven Oil and Natural Gas Properties	$	195,552		$	181,592
Pipelines and Support Equipment		19,101			12,982
Field Operation Vehicles and Other Equipment		4,408			2,981
Wells and Facilities in Progress		34,642			29,629
Unproven Properties		83,143			68,895

Total		336,846			296,079
Less Accumulated Depreciation and Depletion		(70,051	)		(59,484	)
Total	$	266,795		$	236,595


Share of Equity Method Investments:
Pipelines and Support Equipment	$	1,241		$	—
Unproven Properties		296			—

Total		1,537			—
Less Accumulated Depreciation and Depletion		(1	)		—

Total	$	1,536		$	—

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18. OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED)

Our independent engineers, Netherland, Sewell, and Associates, Inc. (“NSAI”) evaluated all of our proved oil and natural gas reserves for the years ended December 31, 2009 and 2007. Schlumberger Consulting and Data Services evaluated the proved reserves on our Marcellus Shale properties for the year ended December 31, 2008, while NSAI evaluated the proved reserves on all of our other properties for the same period. The technical persons responsible for preparing our proved reserves estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. We emphasize that reserve estimates are inherently imprecise. Our oil and natural gas reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available. All of our proved reserves are located within the United States.

Proved oil and natural gas reserves represent the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty will be recoverable in future years from known reservoirs prevailing economic and operating conditions; i.e., prices and costs. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by natural gas and oil and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil and natural gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the installed program has confirmed through production responses that increased recovery will be achieved.

In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. See Note 2, Summary of Significant Accounting Policies—Recently Adopted Accounting Pronouncements. We adopted the rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, are included in our reserves estimates.

Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2009, 2008 and 2007. The reserves are proved and exclude reserves associated with our Southwest Region properties that are shown as Assets Held for Sale on our balance sheet. The total proved reserves for these assets at December 31, 2008 and 2007 were 7,408,188 Mcfe and 7,805,502 Mcfe, respectively.


	2009
	Oil and NGLs (Bbls)		Natural Gas (Mcf)		Mcf Equivalents
Proved Reserves—Beginning of period	5,993,626		30,019,477		65,981,233
Purchases of Reserves in Place	—		—		—
Extensions and Discoveries	940,883		18,422,999		24,068,297
Revisions of Previous Estimates	5,302,862		9,231,194		41,048,366
Production(a)	(727,388	)	(1,510,500	)	(5,874,828	)

Proved Reserves—End of Period	11,509,983		56,163,170		125,223,068

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(a)	Oil production does not include approximately 372 barrels of oil produced attributable to a small oil field that was sold during 2009 and was not evaluated for purposes of reserves in 2008.


	2008
	Oil and NGLs (Bbls)		Natural Gas (Mcf)		Mcf Equivalents
Proved Reserves—Beginning of period	11,962,185		12,715,898		84,489,008
Purchases of Reserves in Place	192,485		16,528,437		17,683,347
Extensions and Discoveries	165,394		—		992,364
Revisions of Previous Estimates	(5,550,249	)	1,812,026		(31,489,468	)
Production	(776,189	)	(1,036,884	)	(5,694,018	)

Proved Reserves—End of Period	5,993,626		30,019,477		65,981,233


	2007
	Oil and NGLs (Bbls)		Natural Gas (Mcf)		Mcf Equivalents
Proved Reserves—Beginning of period	10,767,038		10,473,918		75,076,146
Purchases of Reserves in Place	84,378		—		506,268
Extensions and Discoveries	96,466		1,472,234		2,051,030
Revisions of Previous Estimates	1,784,214		1,555,841		12,261,125
Production	(769,911	)	(786,095	)	(5,405,561	)

Proved Reserves—End of Period	11,962,185		12,715,898		84,489,008

Proved Developed Reserves
December 31, 2007	9,743,031		8,089,555		66,547,741
December 31, 2008	5,186,518		11,695,092		42,814,200
December 31, 2009	8,623,430		16,161,494		67,902,074

19. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

FASB ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proved reserves. We followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0% annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

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The following summary sets forth our future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2009, 2008 and 2007 ($ in thousands) and exclude reserves related to our Southwest Region properties that are shown as Assets Held for Sale on our Consolidated Balance Sheets at December 31, 2008 and 2007:


	2009			2008			2007
Future Cash Inflows	$	844,811	(a)	$	428,419	(b)	$	1,186,744	(c)
Future Costs:
Production		(370,212	)		(210,603	)		(448,475	)
Abandonment		(63,333	)		(63,164	)		(11,777	)
Development		(86,819	)		(51,793	)		(43,692	)

Net Future Cash Inflow Before Income Taxes		324,447			102,859			642,800
Future Income Tax Expense		(53,703	)		—			(218,243	)

Total Future Net Cash Flows Before 10.0% Discount		270,744			102,859			424,557
Less: Effect of a 10.0% Discount Factor		(126,365	)		(33,914	)		(188,447	)

Standardized Measure of Discounted Future Net Cash Flows	$	144,379		$	68,945		$	236,110

(a)	Calculated using weighted average prices of $3.87 per Mcf and $57.65 per barrel of oil

(b)	Calculated using weighted average prices of $5.71 per Mcf and $41.00 per barrel of oil

(c)	Calculated using weighted average prices of $6.79 per Mcf and $92.50 per barrel of oil

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:


	2009			2008			2007
Standardized Measure—Beginning of Period	$	68,945		$	236,110		$	178,334
Revisions of Previous Estimates:
Changes in Prices and Production Costs		16,327			(232,192	)		170,971
Revisions in Quantities		76,433			(46,535	)		55,728
Changes in Future Development Costs		(51,419	)		(13,473	)		(15,444	)
Accretion of Discount and Timing of Future Cash Flows		6,895			23,611			17,834
Net Change in Income Tax(a)		(30,000	)		—			(120,842	)
Purchase of Reserves in Place		—			2,481			1,405
Plus Extensions, Discoveries, and Other Additions		5,715			12,655			4,371
Development Costs Incurred		28,327			42,325			16,397
Sales of Product—Net of Production Costs		(26,376	)		(57,502	)		(35,772	)
Changes in Timing and Other		50,573			111,103			(36,200	)
Future Abandonment Costs		(1,041	)		(9,638	)		(672	)

Standardized Measure—End of Period	$	144,379		$	68,945		$	236,110

(a)

At December 31, 2008, the tax basis of our assets exceeded the future cash flows of our oil and gas properties, which indicates that no future income taxes will be paid. Impairment testing was performed on our oil and gas properties at year end based on escalating future oil and natural gas prices. The standardized measure of discounted future net cash flows is based on the year end SEC commodity prices, which are held constant for the life of the properties.

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20. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Results of operations are equal to revenues, less (a) production costs, (b) exploration expenses, (c) DD&A expenses, and (d) income tax expense (benefit):


	2009			2008		2007
Consolidated Entities:
Revenues
Oil and Natural Gas Sales	$	48,534		$	84,013	$	58,133
Expenses
Production and Lease Operating Expense		22,157			26,511		22,361
Exploration Expense		2,080			3,261		1,238
Depletion, Depreciation, Amortization and Accretion		25,205			37,904		17,804

Total Costs		49,442			67,676		41,403

Pre-tax Operating Income (Loss)		(908	)		16,337		16,730
Income Tax Expense (Benefit)(1)		(361	)		3,006		6,642

Results of Operations for Oil and Gas Producing Activities(2)	$	(547	)	$	13,331	$	10,088

(1)	Computed using the statutory tax rate for each period: 39.8% in 2009; 18.4% in 2008 and; 39.7% in 2007.

(2)	Our share of equity investment results of operations for oil and gas producing activities totaled a loss of $1,000 attributable to Depletion, Depreciation, Amortization and Accretion.

21. LITIGATION

PennTex Illinois and Rex Operating—EPA Consent Decree

In September 2006, the United States Department of Justice (“U.S. DOJ”) and the United States Environmental Protection Agency (“U.S. EPA”) initiated an enforcement action against PennTex Illinois and Rex Operating seeking mandatory injunctive relief and potential civil penalties based on allegations that the companies were violating the Clean Air Act in connection with the release of hydrogen sulfide (H₂S) gas and other volatile organic compounds (“VOC’s”) in the course of the companies’ oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. On April 4, 2007, PennTex Illinois, Rex Operating, the U.S. EPA and U.S. DOJ executed a comprehensive consent decree in which PennTex Illinois and Rex Operating, without any admission of wrongdoing or liability, agreed to install certain control measures and to implement certain operating and maintenance procedures in the Lawrence Field. Under the terms of the proposed consent decree, PennTex Illinois and Rex Operating agreed to establish a monitoring protocol that would be designed to facilitate the reduction of possible emissions of H₂S and VOCs from PennTex Illinois’ operations near Bridgeport and Petrolia, Illinois. Following a public comment period, on June 6, 2007, United States District Court for the Southern District of Illinois granted the United States’ motion for approval and entry of the proposed consent decree, thereby resolving the enforcement action according to the terms described in the consent decree. The consent decree does not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.

Throughout 2009, we implemented the operating and maintenance procedures and completed the installation of all control measures in accordance with the schedule approved by the U.S. EPA. As of December 31, 2009, we believe that we have substantially met all requirements of the consent decree. As of December 31, 2009, we had incurred approximately $8.4 million in costs associated with the implementation of the air emission control program required by the consent decree. On January 8, 2010, we submitted certain proposed revisions to a Directed Inspection and Maintenance Plan previously implemented by us pursuant to the terms of the consent decree. In general, the proposed revisions update the plan to reflect changes in H₂S control measures and procedures implemented in the field and changes in procedures for responding to resident complaints of H₂S odors. The proposed revisions will require the approval of the U.S. EPA, U.S. DOJ and Illinois EPA.

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PennTex Illinois and Rex Operating— Settlement Agreement — H₂S Class Action Litigation

PennTex Illinois and Rex Operating are defendants in a class action lawsuit that has been filed in the United States District Court for the Southern District of Illinois. This action was commenced on October 17, 2006, by plaintiffs Julia Leib (“Leib”) and Lisa Thompson (“Thompson”), individually and as putative class representatives on behalf of all persons and non-governmental entities that own property or reside on property located in the towns of Bridgeport and Petrolia, Illinois. The complaint asserts that the operation of oil wells that are controlled, owned or operated by PennTex Illinois and Rex Operating has resulted in “serious contamination” of the class area with H₂S. The complaint asserts several causes of action, including violation of the Resource Conservation And Recovery Act, Illinois Environmental Protection Act, negligence, private nuisance, trespass, and willful and wanton misconduct. The complaint seeks, among other things, injunctive relief under the Illinois Environmental Protection Act and Illinois common law, compensatory and other damages, punitive damages, and attorneys’ fees and costs. In addition, the complaint seeks the creation of a court-supervised, defendant-financed fund to pay for medical monitoring for the plaintiffs and others in the class area. PennTex Illinois and Rex Operating filed a joint answer to the amended complaint denying virtually all of the allegations in the amended complaint and asserting affirmative defenses thereto.

The plaintiffs filed a motion for class certification on January 22, 2008, which was opposed by PennTex Illinois and Rex Operating. On December 19, 2008, the district court issued a preliminary ruling on certification, indicating its conclusion that several of the class action prerequisites were met and that it was likely to certify a class to adjudicate two issues relating to the emission of H₂S in the putative class area, while reserving all remaining issues for subsequent individual adjudications. The district court denied the plaintiffs’ motion to certify a class in reference to the plaintiffs’ medical monitoring claim. The district court requested that the plaintiffs submit a revised class definition consistent with its order, which was submitted by the plaintiffs on January 16, 2009. On February 26, 2009, the district court issued an order approving the geographic scope of the plaintiffs’ revised class definition. In its order, the district court denied plaintiffs’ request to include all residents and landowners within the geographic area of the class owning property since October 17, 2006, the date the lawsuit was filed, and limited the class to only current property owners. On March 11, 2009, PennTex Illinois and Rex Operating filed a petition for leave to appeal with the United States Court of Appeals for the Seventh Circuit to appeal the district court’s class certification order on an interlocutory basis. On April 2, 2009, the United States Court of Appeals for the Seventh Circuit denied the petition for leave to appeal.

On December 17, 2009, PennTex Illinois and Rex Operating entered into a Settlement Agreement and Release (the “Settlement Agreement”) with Leib and Thompson, individually and on behalf of a certified class, to settle the class action lawsuit. Under the terms of the Settlement Agreement, PennTex Illinois and Rex Operating, without any admission of liability, agreed to pay the class a total of $1.9 million, of which Leib and Thompson will each receive $25,000. Pursuant to the terms of a pollution liability policy with Federal Insurance Company, $1.0 million of the settlement payment will be funded by our insurance carrier. Pursuant to the Settlement Agreement, PennTex Illinois and Rex Operating also agreed to permanently plug four inactive oil wells adjacent to the residences of Leib and Thompson. Pursuant to the terms of the Settlement Agreement, in return for the above consideration, each member of the class, including Leib and Thompson, released all claims against PennTex Illinois and Rex Operating and their affiliates that in any way related to hydrogen sulfide or other environmental conditions in the class area which were the subject of, or could have been the subject of, the claims alleged in the class action lawsuit, including any class action medical monitoring claims. In addition, each class member released any claims related to any future releases of hydrogen sulfide in the class area on the condition that PennTex Illinois and Rex Operating substantially comply with the terms and conditions of the consent decree previously entered into with the U.S. Environmental Protection Agency and the U.S. Department of Justice on September 7, 2006. Leib and Thompson also agreed to release any individual claims they may have for medical monitoring. The Settlement Agreement does not provide for a release of any potential individual claims of other class members since those claims were not the subject of the class action lawsuit.

The Settlement Agreement was conditioned upon the entry of an order of the district court granting preliminary approval of the settlement, which was issued by the district court on December 21, 2009. The

116

Settlement Agreement is also conditioned upon the entry of an order by the district court granting final approval to the settlement and providing for the dismissal of the lawsuit with prejudice. In the preliminary approval order, the district court set a final approval hearing for March 26, 2010. Under the preliminary approval order, members of the class have until March 12, 2010 to object to the proposed settlement as set forth in the Settlement Agreement. The Settlement Agreement will become effective thirty days after the district court has entered the final approval order. In the event that final approval of the Settlement Agreement does not occur, the Settlement Agreement will become null and void, and in such event, we intend to continue to vigorously defend against the claims that have been asserted against PennTex Illinois and Rex Operating in this lawsuit. Because this lawsuit has not proceeded beyond the class certification phase, and because it is usually difficult to predict the outcome of litigation, in the event that final approval of the Settlement Agreement does not occur, we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or to estimate the amount or the range of potential loss should the outcome be unfavorable to us.

Litigation Related to Proposed Oil and Gas Leases in Westmoreland and Clearfield Counties, Pennsylvania

On July 2, 2009, Rex Energy Corporation and its wholly-owned subsidiary, Rex Energy I, LLC (“Rex Energy I”), were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Westmoreland County, Pennsylvania (the “Snyder Case”). The named plaintiffs are five individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated by reason of having signed in 2008 alleged oil and gas lease agreements with Rex Energy I relating to property located in Westmoreland County, Pennsylvania as to which Duncan Land & Energy, Inc. (“Duncan Land”) allegedly acted as land agent for Rex Energy I or Rex Energy Corporation, and as to which the rental or bonus payments described in the alleged oil and gas leases have not been paid. The complaint in the Snyder Case generally asserts that a binding contract was formed between Rex Energy I and each proposed class member when representatives of Duncan Land presented a form of proposed oil and gas lease to each such person, and each such person signed the proposed oil and gas lease form and delivered the executed proposed lease to representatives of Duncan Land. The plaintiffs make this assertion notwithstanding that none of defendants’ employees are believed to have negotiated directly with any of the named plaintiffs or proposed class members; Duncan Land acted as an independent contractor for Rex Energy I pursuant to an agreement that explicitly states that Duncan Land has no authority to bind Rex Energy I to an oil and gas lease; and each of the proposed leases on its face requires the execution of the lease by Rex Energy I. Despite the foregoing, the complaint in the Snyder Case alleges that representatives of Duncan Land had the authority to offer and/or accept each of the proposed oil and gas leases on behalf of Rex Energy I, and also pleads causes of action against Rex Energy I and Rex Energy Corporation premised on theories of breach of contract, tortious interference with contract and civil conspiracy. The plaintiffs seek a judgment declaring that each of the proposed oil and gas leases transferred an interest in real estate to Rex Energy I and constitute binding and enforceable contracts. In addition, the plaintiffs seek a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees.

We intend to vigorously defend against the plaintiffs’ attempts to certify the proposed class and to vigorously defend against all of the claims that have been asserted against Rex Energy I and Rex Energy Corporation in this lawsuit. Because this lawsuit was only recently initiated, we are currently unable to express an opinion with respect to the likelihood of an unfavorable outcome. However, because we have information that allows us to identify the total number of proposed leases that Rex Energy I has rejected that could potentially be within the scope of the proposed class as described in the complaint, we estimate that the amount in controversy would encompass proposed oil and gas leases covering approximately 7,362 acres and a potential obligation for payment of prepaid rentals or bonuses totaling approximately $17.7 million. We are unable to estimate the amount or range of any potential losses that might be associated with other aspects of the plaintiffs’ breach of contract claims in the Snyder Case, or with respect to the plaintiffs’ tort claims in the event of an unfavorable outcome with respect thereto.

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Rex Energy I is also a defendant in six other individual lawsuits involving oil and gas leasing activity that were filed during the Winter of 2008 and the Spring of 2009 by individual plaintiffs in the Court of Common Pleas of Westmoreland County, Pennsylvania. These lawsuits involve similar claims and requests for relief as those made in the Snyder Case described above. Because the lawsuits are in the initial stages of litigation, we are unable to express an opinion with respect to the likelihood of an unfavorable outcome. In the event that the plaintiffs in each of these other lawsuits were to obtain a judgment that their respective proposed oil and gas lease constitutes a binding obligation of Rex Energy I, we estimate that the amount in controversy would encompass proposed oil and gas leases would cover a total of approximately 552 acres and amount to approximately $1.4 million. We are unable to estimate the amount or range of any other potential losses in the event of an unfavorable outcome on the plaintiffs’ claims in these other lawsuits.

On June 5, 2009, R.E. Gas Development, LLC (“R.E. Gas”), a wholly owned subsidiary of Rex Energy Corporation, was named as a defendant in a lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Liegey Case”). The Liegey Case was brought by eight individuals who signed proposed oil and gas leases relating to approximately 127 acres of jointly-owned property located in Clearfield County, Pennsylvania. R.E. Gas elected not to accept the plaintiffs’ proposed oil and gas lease, and as a result, did not pay to each of the plaintiffs the rental consideration set forth in the lease. The complaint in the Liegey Case asserts that binding contracts between R.E. Gas and the plaintiffs were created when each of the plaintiffs executed a proposed oil and gas lease and delivered the executed proposed lease to a representative of Western Land Services, Inc., an independent contractor of R.E. Gas. The complaint in the Liegey Case asserts causes of action against R.E. Gas premised on theories of breach of contract, unjust enrichment and detrimental reliance. The complaint seeks a judgment in favor of the plaintiffs in the amount of $397,933.75, plus interest, costs and attorneys’ fees. We intend to vigorously defend against these claims; however, because this lawsuit is in the initial stages of litigation, we are unable to express an opinion with respect to the likelihood of an unfavorable outcome. In the event that the plaintiffs were successful in the Liegey Case, we estimate that R.E. Gas would be required to pay the plaintiffs an amount no greater than the damages sought in the plaintiffs’ complaint, plus interest, costs and attorneys’ fees.

22. SUBSEQUENT EVENTS

We have evaluated events or transactions that occurred subsequent to December 31, 2009 through the date and time this report on Form 10-K was filed.

On January 21, 2010, we completed an underwritten public offering of 6,900,000 shares of our common stock, which included 900,000 shares of common stock issued upon the full exercise of the underwriters’ over-allotment option, at a public offering price of $12.25 per share. The net proceeds from the offering were approximately $80.2 million, after deducting underwriting discounts, commissions and estimated offering expenses. We intend to use the net proceeds of the offering to fund a portion of our capital expenditure program for 2010 and for other general corporate purposes. Pending these uses, we intend to use a portion of the proceeds to fully repay outstanding borrowings under our Senior Credit Facility, which as of December 31, 2009 totaled $23.0 million, and invest the remainder in short-term, investment grade, interest-bearing securities.

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23. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following tables set forth unaudited financial information on a quarterly basis for each of the last two years.

REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

($ and Shares in Thousands Except per Share Data)


	Rex Energy Corporation			Rex Energy Corporation			Rex Energy Corporation			Rex Energy Corporation
	2009
	March			June			September			December
Revenues	$	8,830		$	11,541		$	13,055		$	15,265
Costs and Expenses		10,179			20,978			14,241			19,861

Net Loss From Continuing Operations		(1,349	)		(9,437	)		(1,186	)		(4,596	)
Net Income From Discontinued Operations		323			—			—			—

Net Loss		(1,026	)		(9,437	)		(1,186	)		(4,596	)
Net Loss Attributable to Noncontrolling Interests		—			—			—			(12	)

Net Loss Attributable to Rex Energy	$	(1,026	)	$	(9,437	)	$	(1,186	)	$	(4,584	)
Earnings per Common Share attributable to Rex common stockholders :
Basic—Continuing Operations	$	(0.04	)	$	(0.26	)	$	(0.03	)	$	(0.12	)
Basic—Discontinued Operations		0.01			—			—			—

Basic—Net Loss	$	(0.03	)	$	(0.26	)	$	(0.03	)	$	(0.12	)
Basic—Weighted Average Shares Outstanding		36,726			36,846			36,844			36,818
Diluted—Continuing Operations	$	(0.04	)	$	(0.26	)	$	(0.03	)	$	(0.12	)
Diluted—Discontinued Operations		0.01			—			—			—

Diluted—Net Loss	$	(0.03	)	$	(0.26	)	$	(0.03	)	$	(0.12	)
Diluted—Weighted Average Shares Outstanding		36,726			36,846			36,844			36,818


	Rex Energy Corporation			Rex Energy Corporation			Rex Energy Corporation			Rex Energy Corporation
	2008
	March			June			September			December
Revenues	$	19,648		$	25,905		$	25,304		$	13,279
Costs and Expenses		26,461			64,293			(11,479	)		45,839

Net Income (Loss) From Continuing Operations		(6,813	)		(38,388	)		36,783			(32,560	)
Net Income (Loss) From Discontinued Operations		(362	)		427			(28	)		(7,741	)

Net Income (Loss)		(7,175	)		(37,961	)		36,755			(40,301	)
Earnings per Common Share attributable to Rex common stockholders (1):
Basic—Continuing Operations	$	(0.22	)	$	(1.12	)	$	1.01		$	(0.89	)
Basic—Discontinued Operations		(0.01	)		0.01			0.00			(0.21	)

Basic—Net Income (Loss)	$	(0.23	)	$	(1.11	)	$	1.01		$	(1.10	)
Basic—Weighted Average Shares Outstanding		30,795			34,361			36,590			36,590
Diluted—Continuing Operations	$	(0.22	)	$	(1.12	)	$	1.00		$	(0.89	)
Diluted—Discontinued Operations		(0.01	)		0.01			0.00			(0.21	)

Diluted—Net Income (Loss)	$	(0.23	)	$	(1.11	)	$	1.00		$	(1.10	)
Diluted—Weighted Average Shares Outstanding		30,795			34,361			36,804			36,590

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ITEM 9.

CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not applicable.

ITEM 9A.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures to ensure that material information relating to the company is made known to the officers who certify the financial statements and to other members of senior management and the audit committee of our board of directors. As of December 31, 2009, an evaluation was performed under the supervision and with the participation of our management, including the President and Chief Executive Officer (the “CEO”) and the Chief Financial Officer (the “CFO”), of the effectiveness of the design and operation of the our disclosure controls and procedures (as defined in Rules 13a-15(e), and 15d-15(e) under the Securities Exchange Act of 1934). An evaluation was conducted to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our CEO and CFO have concluded that our disclosure controls and procedures were effective as of the date of such evaluation.

Changes in Internal Control over Financial Reporting. No change to our internal control over financial reporting occurred during the year ended December 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f), and 15d-15(f) under the Securities Exchange Act of 1934). Management has used the framework set forth in the report entitled Internal Control—Integrated Framework published by the COSO of the Treadway Commission to evaluate the effectiveness of our internal control over financial reporting. Internal control over financial reporting refers to the process designed by, or under the supervision of, our CEO and CFO, and overseen by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:

•

Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company;

•

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with general accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and

•

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, however, neither internal control over financial reporting nor disclosure controls and procedures can provide absolute assurance of achieving financial reporting objectives because of their inherent limitations. Internal control over financial reporting and disclosure controls are processes that involve human diligence and compliance, and are subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting and disclosure controls also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented, detected or reported on a timely basis by internal control over financial reporting or disclosure controls. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design safeguards for these processes that will reduce, although may not eliminate, these risks.

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Management has concluded that our internal controls over financial reporting and our disclosure controls and procedures were effective as of December 31, 2009. Management reviewed the results of their assessment with our Audit Committee. The effectiveness of our internal control over financial reporting as of December 31, 2009 has been audited by Malin, Bergquist & Company, LLP, an independent registered public accounting firm, as stated in their report which is included in Item 8 of this Annual Report on Form 10-K.

ITEM 9B.

OTHER INFORMATION

Not applicable.

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PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated by reference to such information as set forth in our definitive Proxy Statement (the “2010 Proxy Statement”) for our 2010 annual meeting of stockholders. The 2010 Proxy statement will be filed with the SEC not later than 120 days subsequent to December 31, 2009.

ITEM 11.

EXECUTIVE COMPENSATION

The information required by this item is incorporated herein by reference to the 2010 Proxy Statement for the 2010 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2009.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

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PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a)(1) Financial Statements


		Page

Index to Financial Statements		66

Report of Independent Registered Public Accounting Firm—Financial Statements		67

Consolidated and Combined Balance Sheets at December 31, 2009 and 2008		68

Consolidated and Combined Statements of Operations for the Years Ended December 31, 2009, 2008, and 2007		69

Consolidated and Combined Statements of Stockholder’s Equity for the Years Ended December 31, 2009, 2008, and 2007		70

Consolidated and Combined Statements of Cash Flows for the Years Ended December 31, 2009, 2008, and 2007		71

Notes to the Consolidated and Combined Financial Statements		72

(a)(2) Financial Statement Schedules

All other schedules are omitted because they are not applicable, not required, or because the required information is included in the financial statements or related notes.

(a)(3) Exhibits.


Exhibit Number		Exhibit Title
2.1		Agreement and Plan of Merger among New Albany-Indiana, LLC, Rex Energy III LLC, Rex Energy I, LLC and Rex Energy Corporation (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

2.2		Agreement and Plan of Merger among Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy II Alpha Limited Partnership, Rex Energy Royalties Limited Partnership, Rex Energy I, LLC and Rex Energy Corporation (incorporated by reference to Exhibit 2.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

2.3		Contribution Agreement among Lance T. Shaner, Benjamin W. Hulburt, Michael J. Carlson, Jack Shawver, Thomas F. Shields, Thomas C. Stabley, Christopher K. Hulburt, PennTex Energy Inc. and Rex Energy Corporation (incorporated by reference to Exhibit 2.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

3.1*		Certificate of Incorporation of Rex Energy Corporation, as amended.

3.3		Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

4.1		Form of Specimen Common Stock Certificate of Rex Energy Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

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Exhibit Number		Exhibit Title
4.2		Form of Registration Rights Agreement (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.1+		Rex Energy Corporation 2007 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the registrant’s Registration Statement on Form S-1/A filed on June 11, 2007).

10.2		Consent Decree (incorporated by reference to Exhibit 10.5 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

10.3		Independent Director Agreement with John A. Lombardi dated April 1, 2007 (incorporated by reference to Exhibit 10.6 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

10.4		Service Provider Agreement, dated April 1, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.5		Service Level Agreement, dated April 13, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.6		Letter Agreement, dated April 13, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.7		Lease Agreement, dated September 1, 2006, between Shaner Brothers, LLC and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.10 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.8		Promissory Note, dated September 1, 2006, by Rex Energy Operating Corp. to Shaner Brothers, LLC. (incorporated by reference to Exhibit 10.11 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.9		Summary of oral month-to-month administrative services agreement between Shaner Solutions Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.12 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.10		Summary of oral month-to-month agreement regarding use of airplane between Charlie Brown Air Corp. and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.13 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.11		Summary of oral working capital loan agreement between Lance T. Shaner and PennTex Resources Illinois, Inc. (incorporated by reference to Exhibit 10.14 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.12		Amended and Restated Limited Liability Company Agreement, dated June 21, 2007, of L&B Air LLC (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.13		Amended and Restated Limited Partnership Agreement, dated June 21, 2007, of Charlie Brown II Limited Partnership (incorporated by reference to Exhibit 10.16 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

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Exhibit Number		Exhibit Title
10.14		Promissory Note, dated June 21, 2007, by Rex Energy Operating Corp. to Lance T. Shaner (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.15		First Amended and Restated Aircraft Joint Ownership and Management Agreement, dated June 21, 2007, between Charlie Brown Air Corp. and Charlie Brown II Limited Partnership (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.16+		Employment Agreement by and between Benjamin W. Hulburt and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

10.17+		Employment Agreement by and between Thomas C. Stabley and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

10.18+		Employment Agreement by and between Christopher K. Hulburt and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

10.19+		Employment Agreement by and between William L. Ottaviani and Rex Energy Operating Corp. dated August 1, 2008 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 7, 2008).

10.20		Credit Agreement, dated as of September 28, 2007, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, BNP Paribas, as Syndication Agent, Sovereign Bank, as Documentation Agent and The Lenders Party Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on October 3, 2007).

10.21		Guaranty and Collateral Agreement, dated as of September 28, 2007, made by Rex Energy Corporation and each of the other grantors (as defined therein) in favor of KeyBank National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K as filed with the SEC on October 3, 2007).

10.22		Independent Director Agreement by and between Rex Energy Corporation and Daniel J. Churay effective as of October 19, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on October 19, 2007).

10.23		Independent Director Agreement by and between Rex Energy Corporation and John W. Higbee effective as of October 17, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on October 19, 2007).

10.24		Rex Energy Corporation Director Compensation Plan Effective As of January 1, 2008 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 11, 2007).

10.25+		Form of Nonqualified Stock Option Award Agreement for employee common stock option awards under Rex Energy 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.28 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008).

10.26		Form of Nonqualified Stock Option Award Agreement for non-employee director common stock option awards under Rex Energy 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.29 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008).

10.27+		Form of Stock Appreciation Right Award Agreement under Rex Energy 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.30 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008).

125


Exhibit Number		Exhibit Title
10.28+		Form of Restricted Stock Award Agreement under Rex Energy 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed with the SEC on August 6, 2008).

10.29		First Amendment to Credit Agreement, effective as of April 14, 2008, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K field with the SEC on April 18, 2008).

10.30		Purchase Agreement, dated December 23, 2008, by and between Rex Energy I, LLC and Adventure Exploration Partners, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 30, 2008).

10.31		Second Amendment to Credit Agreement, effective December 23, 2008, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on January 9, 2009).

10.32		Operating Agreement of Charlie Brown Air II, LLC dated as of June 26, 2008 (incorporated by reference to Exhibit 10.35 to our Annual Report on Form 10-K/A filed with the SEC on October 9, 2009).

10.33		Letter Agreement, dated as of March 9, 2009, by and between Rex Energy I, LL and Adventure Exploration Partners, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on March 13, 2009).

10.34		Third Amendment to Credit Agreement, effective as of April 20, 2009, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on April 27, 2009).

10.35		Participation and Exploration Agreement dated June 18, 2009 by and among Williams Production Company, LLC, Williams Production Appalachia, LLC, Rex Energy I, LLC and R.E. Gas Development, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).

10.36		Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement dated June 18, 2009 by and among Williams Production Company, LLC, Williams Production Appalachia, LLC, Rex Energy I, LLC and R.E. Gas Development, LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).

10.37		Limited Liability Company Agreement of RW Gathering, LLC effective as of June 18, 2009 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).

10.38		Letter regarding crude oil purchase dated February 27, 2008 by and between Rex Energy Operating Corp. and/or its affiliates and CountryMark Cooperative LLP (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-159802) as filed with the SEC on July 17, 2009).

10.39		Settlement Agreement and Release by and between Julia Leib and Lisa Thompson, individually and on behalf of the certified class, on the one hand, and Rex Energy Operating Corp. and PennTex Resources Illinois, Inc., on the other hand, effective December 17, 2009 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 22, 2009).

126


Exhibit Number		Exhibit Title
10.40		Limited Liability Company Agreement of Keystone Midstream Services, LLC, dated December 21, 2009, by and among R.E. Gas Development, LLC, Stonehenge Energy Resources, L.P. and Keystone Midstream Services, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.41		Contribution Agreement, dated December 21, 2009, by and among R.E. Gas Development, LLC, Stonehenge Energy Resources, L.P. and Keystone Midstream Services, LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.42		Gas Gathering, Compression and Processing Agreement, dated December 21, 2009, by and between R.E. Gas Development, LLC, Keystone Midstream Services, LLC and Rex Energy Corporation (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.43		Fourth Amendment to Credit Agreement, effective as of December 18, 2009, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.44		Assumption Agreement effective as of December 18, 2009 made by R.E. Gas Development, LLC in favor of KeyBank National Association, as Administrative Agent, and the Lenders Party to the Credit Agreement (incorporated by reference to Exhibit 10.5 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.45		Supplement to Guaranty and Collateral Agreement effective as of December 18, 2009 made by Rex Energy Corporation in favor of KeyBank National Association, as Administrative Agent, and the Lenders Party to the Credit Agreement (incorporated by reference to Exhibit 10.6 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.46		Master Crude Purchase Agreement by and among certain direct and indirect wholly owned subsidiaries of Rex Energy Corporation and CountryMark Cooperative, dated December 30, 2009. (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on January 5, 2010).

10.47		Confirmation No. 1 under Master Crude Purchase Agreement by and among certain direct and indirect wholly owned subsidiaries of Rex Energy Corporation and CountryMark Cooperative, dated December 30, 2009, for period commencing on January 1, 2010 through December 31, 2010 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on January 5, 2010).

21.1*		Subsidiaries of the Registrant.

23.1*		Consent of Malin, Bergquist & Company, LLP.

23.2*		Consent of Netherland, Sewell & Associates, Inc.

31.1*		Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.

31.2*		Certification of Chief Financial Officer (Principal Financial and Principal Accounting Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.

32.1*		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.

99.1*		Report of Netherland, Sewell & Associates, Inc.

*	Filed herewith.

+	Indicates management contract or compensation plan or arrangement.

127

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and gas industry terms used in this report:

Basin. A large natural depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, of crude oil.

Bcf. Billion cubic feet, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

Bopd. Barrels of oil per day.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or gas.

Development or Developmental well. A well drilled within the proved boundaries of an oil or gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses, taxes and the royalty burden.

Exploitation. A drilling or other project which may target proved or unproved reserves (such as probable or possible reserves), but generally is expected to have lower risk.

Exploration or Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.

Injection well or Injection. A well which is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.

Lease operating expenses. The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

128

MBOE. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet of natural gas.

Mcfd. One thousand cubic feet of natural gas per day.

MMBbls. One million barrels of oil or other liquid hydrocarbons.

MMBOE. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of gas.

MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

NYMEX. New York Mercantile Exchange.

PV-10 or present value of estimated future cash flows. An estimate of the present value of the estimated future cash flows from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future cash flows are discounted at an annual rate of 10%, in accordance with the Securities and Exchange Commission’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future cash flows are made using oil and gas prices and operating costs at the date indicated and held constant for the life of the reserves.

Primary recovery. The period of production in which oil and natural gas is produced from its reservoir through the wellbore without enhanced recovery technologies, such as water floods or ASP floods.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed non-producing reserves or PDNP. Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved developed producing reserves or PDP. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, gas and gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

129

Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The addition of production from another interval or formation in an existing wellbore.

Reserve life index. An index calculated by dividing year-end proved reserves by the average production during the past year to estimate the number of years of remaining production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Secondary recovery. An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and waterflooding are examples of this technique.

Tertiary recovery. The third stage of hydrocarbon production during which sophisticated techniques that alter the original properties of the oil are used. Chemical flooding (including ASP flooding), miscible displacement and thermal flooding are examples of this technique.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether or not such acreage contains proved reserves.

Waterflooding. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

Workover. Operations on a producing well to restore or increase production.

130

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: March 3, 2010


REX ENERGY CORPORATION

By:		/s/ BENJAMIN W. HULBURT
		Benjamin W. Hulburt
		*President and Chief Executive Officer*

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


/s/ LANCE T. SHANER Lance T. Shaner	Chairman of the Board	March 3, 2010

/s/ BENJAMIN W. HULBURT Benjamin W. Hulburt	President, Chief Executive Officer and Director (Principal Executive Officer)	March 3, 2010

/s/ THOMAS C. STABLEY Thomas C. Stabley	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 3, 2010

/s/ DANIEL J. CHURAY Daniel J. Churay	Director	March 3, 2010

/s/ JOHN W. HIGBEE John W. Higbee	Director	March 3, 2010

/s/ JOHN A. LOMBARDI John A. Lombardi	Director	March 3, 2010

131

EXHIBIT INDEX


Exhibit Number		Exhibit Title
2.1		Agreement and Plan of Merger among New Albany-Indiana, LLC, Rex Energy III LLC, Rex Energy I, LLC and Rex Energy Corporation (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

2.2		Agreement and Plan of Merger among Douglas Oil & Gas Limited Partnership, Douglas Westmoreland Limited Partnership, Midland Exploration Limited Partnership, Rex Energy Limited Partnership, Rex Energy II Limited Partnership, Rex Energy II Alpha Limited Partnership, Rex Energy Royalties Limited Partnership, Rex Energy I, LLC and Rex Energy Corporation (incorporated by reference to Exhibit 2.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

2.3		Contribution Agreement among Lance T. Shaner, Benjamin W. Hulburt, Michael J. Carlson, Jack Shawver, Thomas F. Shields, Thomas C. Stabley, Christopher K. Hulburt, PennTex Energy Inc. and Rex Energy Corporation (incorporated by reference to Exhibit 2.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

3.1*		Certificate of Incorporation of Rex Energy Corporation, as amended.

3.3		Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

4.1		Form of Specimen Common Stock Certificate of Rex Energy Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

4.2		Form of Registration Rights Agreement (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.1+		Rex Energy Corporation 2007 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the registrant’s Registration Statement on Form S-1/A filed on June 11, 2007).

10.2		Consent Decree (incorporated by reference to Exhibit 10.5 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

10.3		Independent Director Agreement with John A. Lombardi dated April 1, 2007 (incorporated by reference to Exhibit 10.6 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).

10.4		Service Provider Agreement, dated April 1, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.5		Service Level Agreement, dated April 13, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

10.6		Letter Agreement, dated April 13, 2007, between Shaner Hotel Group Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

132


Exhibit Number		Exhibit Title
10.7		Lease Agreement, dated September 1, 2006, between Shaner Brothers, LLC and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.10 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.8		Promissory Note, dated September 1, 2006, by Rex Energy Operating Corp. to Shaner Brothers, LLC. (incorporated by reference to Exhibit 10.11 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.9		Summary of oral month-to-month administrative services agreement between Shaner Solutions Limited Partnership and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.12 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.10		Summary of oral month-to-month agreement regarding use of airplane between Charlie Brown Air Corp. and Rex Energy Operating Corp. (incorporated by reference to Exhibit 10.13 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.11		Summary of oral working capital loan agreement between Lance T. Shaner and PennTex Resources Illinois, Inc. (incorporated by reference to Exhibit 10.14 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.12		Amended and Restated Limited Liability Company Agreement, dated June 21, 2007, of L&B Air LLC (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.13		Amended and Restated Limited Partnership Agreement, dated June 21, 2007, of Charlie Brown II Limited Partnership (incorporated by reference to Exhibit 10.16 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.14		Promissory Note, dated June 21, 2007, by Rex Energy Operating Corp. to Lance T. Shaner (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.15		First Amended and Restated Aircraft Joint Ownership and Management Agreement, dated June 21, 2007, between Charlie Brown Air Corp. and Charlie Brown II Limited Partnership (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on July 6, 2007).

10.16+		Employment Agreement by and between Benjamin W. Hulburt and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

10.17+		Employment Agreement by and between Thomas C. Stabley and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

10.18+		Employment Agreement by and between Christopher K. Hulburt and Rex Energy Operating Corp. dated August 1, 2007 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K as filed with the SEC on August 7, 2007).

10.19+		Employment Agreement by and between William L. Ottaviani and Rex Energy Operating Corp. dated August 1, 2008 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on August 7, 2008).

10.20		Credit Agreement, dated as of September 28, 2007, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, BNP Paribas, as Syndication Agent, Sovereign Bank, as Documentation Agent and The Lenders Party Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on October 3, 2007).

133


Exhibit Number		Exhibit Title
10.21		Guaranty and Collateral Agreement, dated as of September 28, 2007, made by Rex Energy Corporation and each of the other grantors (as defined therein) in favor of KeyBank National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K as filed with the SEC on October 3, 2007).

10.22		Independent Director Agreement by and between Rex Energy Corporation and Daniel J. Churay effective as of October 19, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on October 19, 2007).

10.23		Independent Director Agreement by and between Rex Energy Corporation and John W. Higbee effective as of October 17, 2007 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on October 19, 2007).

10.24		Rex Energy Corporation Director Compensation Plan Effective As of January 1, 2008 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 11, 2007).

10.25+		Form of Nonqualified Stock Option Award Agreement for employee common stock option awards under Rex Energy 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.28 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008).

10.26		Form of Nonqualified Stock Option Award Agreement for non-employee director common stock option awards under Rex Energy 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.29 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008).

10.27+		Form of Stock Appreciation Right Award Agreement under Rex Energy 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.30 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008).

10.28+		Form of Restricted Stock Award Agreement under Rex Energy 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed with the SEC on August 6, 2008).

10.29		First Amendment to Credit Agreement, effective as of April 14, 2008, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K field with the SEC on April 18, 2008).

10.30		Purchase Agreement, dated December 23, 2008, by and between Rex Energy I, LLC and Adventure Exploration Partners, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 30, 2008).

10.31		Second Amendment to Credit Agreement, effective December 23, 2008, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on January 9, 2009).

10.32		Operating Agreement of Charlie Brown Air II, LLC dated as of June 26, 2008 (incorporated by reference to Exhibit 10.35 to our Annual Report on Form 10-K/A filed with the SEC on October 9, 2009).

10.33		Letter Agreement, dated as of March 9, 2009, by and between Rex Energy I, LL and Adventure Exploration Partners, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on March 13, 2009).

134


Exhibit Number		Exhibit Title
10.34		Third Amendment to Credit Agreement, effective as of April 20, 2009, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on April 27, 2009).

10.35		Participation and Exploration Agreement dated June 18, 2009 by and among Williams Production Company, LLC, Williams Production Appalachia, LLC, Rex Energy I, LLC and R.E. Gas Development, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).

10.36		Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement dated June 18, 2009 by and among Williams Production Company, LLC, Williams Production Appalachia, LLC, Rex Energy I, LLC and R.E. Gas Development, LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).

10.37		Limited Liability Company Agreement of RW Gathering, LLC effective as of June 18, 2009 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed with the SEC on June 24, 2009).

10.38		Letter regarding crude oil purchase dated February 27, 2008 by and between Rex Energy Operating Corp. and/or its affiliates and CountryMark Cooperative LLP (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-159802) as filed with the SEC on July 17, 2009).

10.39		Settlement Agreement and Release by and between Julia Leib and Lisa Thompson, individually and on behalf of the certified class, on the one hand, and Rex Energy Operating Corp. and PennTex Resources Illinois, Inc., on the other hand, effective December 17, 2009 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 22, 2009).

10.40		Limited Liability Company Agreement of Keystone Midstream Services, LLC, dated December 21, 2009, by and among R.E. Gas Development, LLC, Stonehenge Energy Resources, L.P. and Keystone Midstream Services, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.41		Contribution Agreement, dated December 21, 2009, by and among R.E. Gas Development, LLC, Stonehenge Energy Resources, L.P. and Keystone Midstream Services, LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.42		Gas Gathering, Compression and Processing Agreement, dated December 21, 2009, by and between R.E. Gas Development, LLC, Keystone Midstream Services, LLC and Rex Energy Corporation (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.43		Fourth Amendment to Credit Agreement, effective as of December 18, 2009, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.44		Assumption Agreement effective as of December 18, 2009 made by R.E. Gas Development, LLC in favor of KeyBank National Association, as Administrative Agent, and the Lenders Party to the Credit Agreement (incorporated by reference to Exhibit 10.5 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

10.45		Supplement to Guaranty and Collateral Agreement effective as of December 18, 2009 made by Rex Energy Corporation in favor of KeyBank National Association, as Administrative Agent, and the Lenders Party to the Credit Agreement (incorporated by reference to Exhibit 10.6 to our Current Report on Form 8-K filed with the SEC on December 28, 2009).

135


Exhibit Number		Exhibit Title
10.46		Master Crude Purchase Agreement by and among certain direct and indirect wholly owned subsidiaries of Rex Energy Corporation and CountryMark Cooperative, dated December 30, 2009. (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on January 5, 2010).

10.47		Confirmation No. 1 under Master Crude Purchase Agreement by and among certain direct and indirect wholly owned subsidiaries of Rex Energy Corporation and CountryMark Cooperative, dated December 30, 2009, for period commencing on January 1, 2010 through December 31, 2010 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on January 5, 2010).

21.1*		Subsidiaries of the Registrant.

23.1*		Consent of Malin, Bergquist & Company, LLP.

23.2*		Consent of Netherland, Sewell & Associates, Inc.

31.1*		Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.

31.2*		Certification of Chief Financial Officer (Principal Financial and Principal Accounting Officer) pursuant to Section 302 of the Sarbanes-Oxley Act.

32.1*		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.

99.1*		Report of Netherland, Sewell & Associates, Inc.

*	Filed herewith.

+	Indicates management contract or compensation plan or arrangement.

136

REX ENERGY CORP - FORM 10-K - March 3, 2010

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