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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

OR

 

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                          to                         .

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)

 

 

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 website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files)    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined 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

44,400,722 common shares were outstanding on November 2, 2011.

 

 

 

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REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD SEPTEMBER 30, 2011

INDEX

 

				PAGE
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS					3
PART I. FINANCIAL INFORMATION
Item 1.		Financial Statements			4
		Consolidated Balance Sheets As of September 30, 2011 (Unaudited) and December 31, 2010			4
		Consolidated Statements of Operations (Unaudited) for the three-month and nine-month periods ended September 30, 2011 and September 30, 2010			5
		Consolidated Statement of Changes in Owners’ Equity (Unaudited) for the nine-month period ended September 30, 2011			6
		Consolidated Statements of Cash Flows (Unaudited) for the nine-month periods ended September 30, 2011 and September 30, 2010			7
		Notes to Consolidated Financial Statements (Unaudited)			8
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations.			27
Item 3.		Quantitative and Qualitative Disclosure About Market Risk			38
Item 4.		Controls and Procedures			39
PART II. OTHER INFORMATION					40
Item 1.		Legal Proceedings			40
Item 1A.		Risk Factors			40
Item 6.		Exhibits			41
SIGNATURES					42
EXHIBIT INDEX					43

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains 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 facts included in this report, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans and objectives of management for future operations, 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 similar terminology.

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

 

•

uncertainties regarding the economic conditions in the United States and globally;

 

•

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 outcomes; and

 

•

other factors discussed under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010 filed with the U.S. Securities and Exchange Commission.

Because these statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. You are cautioned not to place undue reliance on forward looking-statements, which speak only as of the date of this report. 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.

 

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Item 1. Financial Statements.

REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in Thousands, Except Shares and per Share Amounts)

 

		September 30,  2011 (unaudited)				December 31, 2010
ASSETS
Current Assets
Cash and Cash Equivalents		$	9,601			$	11,008
Accounts Receivable			17,555				28,860
Short-Term Derivative Instruments			6,549				4,564
Inventory, Prepaid Expenses and Other			1,437				1,327
Total Current Assets			35,142				45,759
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties			314,975				241,586
Unevaluated Oil and Gas Properties			133,812				91,574
Other Property and Equipment			42,720				42,226
Wells and Facilities in Progress			72,246				37,393
Pipelines			4,080				4,080
Total Property and Equipment			567,833				416,859
Less: Accumulated Depreciation, Depletion and Amortization			(110,499	)			(93,063	)
Net Property and Equipment			457,334				323,796
Restricted Cash			25				16,111
Intangible Assets and Other Assets – Net			1,956				1,570
Equity Method Investments			37,282				18,399
Long-Term Deferred Tax Asset			1,050				0
Long-Term Derivative Instruments			5,061				1,450
Total Assets		$	537,850			$	407,085
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable		$	54,018			$	49,401
Accrued Expenses			13,904				10,168
Short-Term Derivative Instruments			0				1,860
Current Deferred Tax Liability			1,527				1,908
Total Current Liabilities			69,449				63,337
Senior Secured Line of Credit and Long-Term Debt			154,095				10,120
Long-Term Derivative Instruments			0				1,517
Long-Term Deferred Tax Liability			189				5,930
Other Deposits and Liabilities			847				4,283
Future Abandonment Cost			18,338				17,222
Total Liabilities		$	242,918			$	102,409
Commitments and Contingencies (See Note 11)
Stockholders’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 44,342,522 shares issued and outstanding on September 30, 2011 and 44,306,677 shares issued and outstanding on December 31, 2010.			44				44
Additional Paid-In Capital			376,370				373,856
Accumulated Deficit			(81,770	)			(69,519	)
Rex Energy Stockholders’ Equity			294,644				304,381
Noncontrolling Interests			288				295
Total Stockholders’ Equity			294,932				304,676
Total Liabilities and Stockholders’ Equity		$	537,850			$	407,085

See accompanying notes to the unaudited consolidated financial statements

 

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in Thousands, Except per Share Data)

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
		2011				2010				2011				2010
OPERATING REVENUE
Oil and Natural Gas Sales		$	30,342			$	16,419				81,572			$	48,467
Other Revenue			496				437				1,837				834
TOTAL OPERATING REVENUE			30,838				16,856				83,409				49,301
OPERATING EXPENSES
Production and Lease Operating Expense			9,100				6,471				24,457				18,182
General and Administrative Expense			4,887				5,015				20,059				13,750
(Gain) Loss on Disposal of Asset			6				(16,485	)			464				(16,493	)
Impairment Expense			2,379				2,419				14,182				3,567
Exploration Expense			30,552				(474	)			33,765				2,972
Depreciation, Depletion, Amortization and Accretion			7,679				4,979				19,718				15,211
Other Operating Expense			595				295				1,552				861
TOTAL OPERATING EXPENSES			55,198				2,220				114,197				38,050
INCOME (LOSS) FROM OPERATIONS			(24,360	)			14,636				(30,788	)			11,251
OTHER INCOME (EXPENSE)
Interest Income			1				6				10				56
Interest Expense			(475	)			(430	)			(1,034	)			(761	)
Gain on Derivatives, Net			12,174				1,988				12,787				10,040
Other Income (Expense)			41				(25	)			59				(168	)
Gain (Loss) on Equity Method Investments			105				(25	)			(165	)			(42	)
TOTAL OTHER INCOME			11,846				1,514				11,657				9,125
INCOME (LOSS) BEFORE INCOME TAX			(12,514	)			16,150				(19,131	)			20,376
Income Tax Benefit (Expense)			4,368				(6,610	)			6,866				(8,034	)
INCOME (LOSS)			(8,146	)			9,540				(12,265	)			12,342
Net Income (Loss) Attributable to Noncontrolling Interests			44				(88	)			(14	)			(208	)
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY		$	(8,190	)		$	9,628				(12,251	)		$	12,550
Earnings per common share:
Basic – Net Income (Loss) Attributable to Rex Common Shareholders		$	(0.18	)		$	0.22			$	(0.28	)		$	0.29
Basic – Weighted Average Shares of Common Stock Outstanding			44,384				44,051				44,353				43,409
Diluted – Net Income (Loss) Attributable to Rex Common Shareholders		$	(0.18	)		$	0.22				(0.28	)		$	0.29
Diluted – Weighted Average Shares of Common Stock Outstanding			44,384				44,103				44,353				43,495

See accompanying notes to the unaudited consolidated financial statements

 

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

FOR THE NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2011

(Unaudited, $ in Thousands)

 

		Common Stock								Additional Paid-In Capital				Accumulated Deficit				Rex Energy Stockholders’ Equity				Noncontrolling Interests
		Shares				Par Value
BALANCE December 31, 2010			44,307			$	44			$	373,856			$	(69,519	)		$	304,381			$	295
Non-Cash Compensation Expense			0				0				1,354				0				1,354				0
Stock Option Exercises			122				0				1,160				0				1,160				0
Issuance of Restricted Stock, Net of Forfeitures			(86	)			0				0				0				0				0
Capital Contributions			0				0				0				0				0				7
Net Loss			0				0				0				(12,251	)			(12,251	)			(14	)
BALANCE September 30, 2011			44,343			$	44			$	376,370			$	(81,770	)		$	294,644			$	288

See accompanying notes to the unaudited consolidated financial statements

 

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

 

		For the Nine Months  Ended September 30,
		2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		$	(12,265	)		$	12,342
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss from Equity Method Investments			165				42
Non-cash Expenses			1,435				1,455
Depreciation, Depletion, Amortization and Accretion			19,718				15,211
Unrealized Gain on Derivatives			(8,972	)			(10,099	)
Dry Hole Expense			30,529				0
Deferred Income Tax Expense (Benefit)			(7,172	)			8,034
Impairment Expense			14,182				3,567
(Gain) Loss on Sale of Asset			464				(16,493	)
Changes in operating assets and liabilities
Accounts Receivable			11,304				(3,927	)
Inventory, Prepaid Expenses and Other Assets			(108	)			(486	)
Accounts Payable and Accrued Expenses			3,632				10,563
Other Assets and Liabilities			(1,855	)			(9,608	)
NET CASH PROVIDED BY OPERATING ACTIVITIES			51,057				10,601
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Phase I and II Leasing Initiative			3,137				0
Like-Kind Exchange Investment			0				(30,555	)
Change in Restricted Cash			16,086				0
Equity Method Investments			(14,412	)			(11,441	)
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets			2,570				79,118
Acquisitions of Undeveloped Acreage			(60,468	)			(68,357	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment			(143,894	)			(52,105	)
NET CASH USED IN INVESTING ACTIVITIES			(196,981	)			(83,340	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of Long-Term Debt and Line of Credit			0				(23,000	)
Proceeds from Long-Term Debt and Line of Credit			144,000				75,000
Repayments of Loans and Other Notes Payable			(650	)			(488	)
Capital Contributions by the Partners of Equity Method Investments and Consolidated Joint Ventures			7				245
Proceeds from the Issuance of Common Stock, Net of Issuance Costs			1,160				80,192
NET CASH PROVIDED BY FINANCING ACTIVITIES			144,517				131,949
NET INCREASE (DECREASE) IN CASH			(1,407	)			59,210
CASH – BEGINNING			11,008				5,582
CASH – ENDING		$	9,601			$	64,792
SUPPLEMENTAL DISCLOSURES
Interest Paid			748				473
Cash Paid for Income Taxes			49				0
NON-CASH ACTIVITIES
Equipment Financing			340				926

See accompanying notes to the unaudited consolidated financial statements

 

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REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent oil and gas company with operations currently focused in the Illinois, Appalachian and Denver-Julesburg (“DJ”) Basins. In the Illinois Basin, in addition to our developmental oil drilling, we are focused on the implementation of enhanced oil recovery on our properties. In the Appalachian Basin, we are focused on our Marcellus Shale drilling projects. Our focus thus far in the DJ Basin has been on drilling, testing and evaluating our acreage that we believe to be prospective for horizontal oil well drilling in the Niobrara formation. Our balanced growth strategy is focused on developing our higher potential exploration drilling prospects and actively seeking to acquire complementary oil and natural gas properties.

The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

The interim Consolidated Financial Statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Actual results may differ from those estimates and results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in prices for crude oil and natural gas, future commodity prices for financial derivative instruments, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market consumption, interruption in production, our ability to obtain additional capital, and the success of oil and natural gas recovery techniques.

Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2010.

Subsidiary Guarantors

We filed a registration statement on Form S-3, which became effective June 15, 2011, with respect to certain securities described therein, including debt securities, which may be guaranteed by certain of our subsidiaries. Rex Energy Corporation is a holding company with no independent assets or operations. We contemplate that if guaranteed debt securities are offered pursuant to the registration statement, all guarantees will be full and unconditional and joint and several and any subsidiaries other than the subsidiary guarantors will be minor. In addition, there are no significant restrictions on the ability of Rex Energy Corporation to receive funds from our subsidiaries through dividends, loans, advances or otherwise.

2. 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.

Accretion expense during the three-month periods ended September 30, 2010 and September 30, 2011 totaled approximately $0.4 million and $0.3 million, respectively. Accretion expense during the nine-month periods ended September 30, 2010 and September 30, 2011 totaled approximately $1.3 million and $1.0 million, respectively. These amounts are recorded as depreciation, depletion and amortization expense (“DD&A”) on our Consolidated Statements of Operations. In accordance with the terms of our Participation and Exploration Agreements (“PEAs”) with Williams Companies and Sumitomo Corporation (for additional information see Note 3, Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements), we account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells.

 

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		September 30, 2011
		($ in Thousands)
Beginning Balance at December 31, 2010		$	17,222
Asset Retirement Obligation Incurred			221
Asset Retirement Obligation Settled			(152	)
Asset Retirement Obligation Accretion Expense			1,047
Total Future Abandonment Cost		$	18,338

3. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS

Acquisitions

Each of the transactions listed below pertains to the leasing of large tracts of acreage and were recorded as Unevaluated Oil and Gas Properties on our Consolidated Balance Sheets. As of September 30, 2011, we had incurred capital expenditures of approximately $204.4 million, of which approximately $60.5 million was for the acquisition of unproved properties in the normal course of business which were not individually significant.

In July 2010, we acquired a 100% working interest in certain undeveloped oil and gas leases covering approximately 18,000 net acres located in the DJ Basin in Laramie County, Wyoming. The acreage was acquired for approximately $18.4 million.

Dispositions

On September 30, 2010, we entered into a joint venture transaction with Sumitomo Corporation (“Sumitomo”). In Butler County, Pennsylvania we sold a 15% non-operated interest in approximately 40,700 net acres for approximately $30.6 million in cash at closing and $30.6 million in the form of a drilling carry of 80% of our drilling and completion costs in the area. Pursuant to the Participation and Exploration Agreement (the “Sumitomo PEA”), Sumitomo agreed to pay all of the costs to lease approximately 9,000 net acres in the Butler County Area of Mutual Interest (“AMI”) (the “Phase I Leasing”), and to pay to us a leasing management fee of $1,000 per net acre during the Phase I Leasing. The Phase I Leasing and drilling carry for Butler County were completed during the first quarter of 2011, resulting in final ownership percentages of 70% to us and 30% to Sumitomo. The cost of future leasing activities will be shared on a 70/30 basis, with Sumitomo paying to us a management fee of $150 per net acre acquired. In addition to the sale of undeveloped acreage, we also sold to Sumitomo 30% of our interests in 20 Marcellus Shale wells within the Butler County area and 30% of our interest in Keystone Midstream Services, LLC (“Keystone Midstream”) (for additional information on Keystone Midstream, see Note 13, Variable Interest Entities, and Note 14, Equity Method Investments, to our Consolidated Financial Statements).

In our Marcellus Shale joint venture project areas with Williams Production Company, LLC and Williams Production Appalachia, LLC (collectively, “Williams”), we sold to Sumitomo 20% of our interests in 23,500 net acres for approximately $19.0 million in cash at closing and $19.0 million in the form of a drilling carry of 80% of our drilling and completion costs in the areas. In addition, we sold 20% of our interest in 19 Marcellus Shale wells located in the Williams joint venture areas and 20% of our interest in RW Gathering, LLC (“RW Gathering”) (for additional information on RW Gathering, see Note 14, Equity Method Investments, to our Consolidated Financial Statements).

In addition to the areas above, we sold to Sumitomo 50% of our interests in approximately 4,500 net acres in Fayette and Centre Counties, Pennsylvania for $9.2 million in cash at closing and $9.2 million in the form of a drilling carry of 80% of our drilling and completion costs. As of September 30, 2011, there were no remaining drilling carries with Sumitomo.

4. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In May 2011, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, Fair Vale Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. ASU 2011-04 generally provides a uniform framework for fair value measurements and related disclosures between GAAP and International Financial Reporting Standards (“IFRS”). Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements, quantitative information about unobservable inputs used, a description of the valuation process used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a nonfinancial asset that is different from the asset’s highest and best use, the reason for the difference; (3) for financial

 

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instruments not measured at fair value but for which disclosure of fair value is required, the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. This update is effective for annual and interim periods beginning on or after December 15, 2011. We are currently evaluating the effect of ASU 2011-04 on our financial statements and related disclosures.

5. CONCENTRATIONS OF CREDIT RISK

At times during the three and nine-month periods ended September 30, 2011, our cash balance exceeded the Federal Deposit Insurance Corporation’s limit. 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 counterparties 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 high-quality counterparties. Our counterparties are investment grade financial institutions and lenders in our Senior Credit Facility (see Note 6, Long-term Debt and Other Obligations, to our Consolidated Financial Statements). We have a master netting agreement in place with our counterparties 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 cash settlement date. For additional information, see Note 7, Fair Value of Financial and Derivative Instruments, to our Consolidated Financial Statements.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At December 31, 2010, we carried approximately $8.1 million in production receivables, of which approximately $5.1 million were production receivables due from a single customer, Countrymark Cooperative LLP (“Countrymark”). At September 30, 2011, we carried approximately $11.8 million in production receivables, of which approximately $4.8 million were production receivables due from Countrymark. We have a standby letter of credit from Countrymark as support for their monetary obligations to us, up to $4.0 million. To help offset this risk, we operate 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 Basin operations 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. LONG-TERM DEBT AND OTHER OBLIGATIONS

We maintain a revolving credit facility evidenced by the Credit Agreement, dated September 28, 2007, with KeyBank National Association as Administrative Agent; Royal Bank of Canada, as Syndication 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. As of September 30, 2011, the borrowing base under the Senior Credit Facility was $240.0 million; however, the revolving credit facility may be increased up to $500 million upon re-determinations of the borrowing base, consent of the lenders and other conditions described in the agreement. The borrowing base is re-determined by the bank group semi-annually. As of September 30, 2011, loans made under the Senior Credit Facility were set to mature on September 28, 2015. In certain circumstances, we may be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months.

Borrowings under the Senior Credit Facility bear interest, at our election, at the Adjusted LIBOR 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 2.75% for Eurodollar loans and 0.50% to 1.50% for ABR loans. The Alternative 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) LIBOR 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 0.375% to 0.50%.

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 rates 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 $20.0 million and 75% of the then outstanding principal amount of our debt for borrowed money, which bears interest at a floating rate. For further information on our derivative instruments, see Note 7, Fair Value of Financial and Derivative Instruments, to our Consolidated Financial Statements.

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;

 

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sell assets; make loans to others; make investments; enter into mergers; incur liens; and enter into agreements regarding swap and other derivative transactions. 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 Pennsylvania, 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.

The Senior Credit Facility also requires that we meet, on a quarterly basis, minimum financial requirements of consolidated current ratio, EBITDAX to interest expense and total debt to EBITDAX. EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, such as our commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash activity. The financial covenant states that as of the last day of any fiscal quarter, our ratio of consolidated current assets, which includes the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day is to not be less than 1.0 to 1.0. On that basis, our current ratio as of September 30, 2011 was approximately 1.7 to 1.0. Additionally, the covenant 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, known as our interest coverage ratio, is not to be less than 3.0 to 1.0. Our interest coverage ratio as of September 30, 2011 was approximately 38.3 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 not to exceed 4.0 to 1.0. Our ratio of total debt to EBITDAX as of September 30, 2011 was approximately 3.0 to 1.0.

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 other obligations consisted of the following at September 30, 2011 and December 31, 2010:

 

		September 30, 2011				December 31, 2010
		($ in Thousands)				($ in Thousands)
Senior Credit Facility(a)		$	154,000			$	10,000
Capital Leases and Other Obligations(a)			624				949
Total Debts			154,624				10,949
Less Current Portion of Long-Term Debt(b)			(529	)			(829	)
Total Long-Term Debts		$	154,095			$	10,120

 

(a)

The Senior Credit Facility requires us to make monthly payments of interest on the outstanding balance of loans made under the agreement. Loans made under the Senior Credit Facility mature on September 28, 2015, and in certain circumstances, we may be required to prepay the loans. The average interest rate on borrowings under our Senior Credit Facility for the nine months ended September 30, 2011 was approximately 2.5%. The average interest rate on our capital leases and other obligations for the nine months ended September 30, 2011 was approximately 2.3%.

(b)	Included in Accounts Payable on our Consolidated Balance Sheets.

7. FAIR VALUE OF FINANCIAL 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 on the settlement dates, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling on the settlement dates, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of September 30, 2011, our oil and natural gas derivative commodity instruments consisted of fixed rate swap contracts, collars, swaptions, puts and put spreads. Accordingly, associated unrealized gains and losses are recorded directly as other income or expense under the heading Gain on Derivatives, Net.

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 settlement 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 settlement 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. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless

 

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the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. Swaption agreements provide options to counterparties to extend swaps into subsequent years.

We enter into the majority of our derivative arrangements with three counterparties and have a netting agreement in place. We present our derivatives as gross assets or liabilities on our Consolidated Balance Sheets. We do not obtain collateral to support the derivative agreements, but monitor the financial viability of our counterparties and believe our credit risk is minimal on these transactions. For additional information on the credit risk with regards to our counterparties, see Note 5, Concentrations of Credit Risk, to our Consolidated 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 on Derivatives, Net under Other Income (Expense).

We received net payments of $1.6 million and $0.4 million under these commodity derivative instruments during the three-month periods ended September 30, 2011 and 2010, respectively, and received net payments of $3.8 million and $0.5 million for the nine-month periods ended September 20, 2011 and 2010, respectively. Unrealized gains associated with our commodity derivative instruments amounted to $10.6 million and $9.0 million for the three and nine months ended September 30, 2011, respectively, as compared to unrealized gains of approximately $1.8 million and $10.1 million for the three and nine months ended September 30, 2010, 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 three and nine months ended September 30, 2011 and 2010 ($ in thousands):

 

		Three Months Ended September 30, 2011												Three Months Ended September 30, 2010
		Realized Gains (Losses)				Unrealized Gains (Losses)				Total				Realized Gains (Losses)				Unrealized Gains (Losses)				Total
Crude Oil
Reclassification of settled contracts included in prior periods mark-to-market adjustment		$	0			$	558			$	558			$	0			$	819			$	819
Mark-to-market fair value adjustments			0				6,562				6,562				0				(1,941	)			(1,941	)
Settlement of contracts (a)			(5	)			0				(5	)			(630	)			0				(630	)
Crude Oil Total			(5	)			7,120				7,115				(630	)			(1,122	)			(1,752	)
Natural Gas
Reclassification of settled contracts included in prior periods mark-to-market adjustment			0				(1,142	)			(1,142	)			0				(846	)			(846	)
Mark-to-market fair value adjustments			0				4,594				4,594				0				3,549				3,549
Settlement of contracts (a)			1,607				0				1,607				1,050				0				1,050
Natural Gas Total			1,607				3,452				5,059				1,050				2,703				3,753
Interest Rate
Reclassification of settled contracts included in prior periods mark-to-market adjustment			0				0				0				0				213				213
Mark-to-market fair value adjustments			0				0				0				0				(30	)			(30	)
Settlement of contracts (a)			0				0				0				(196	)			0				(196	)
Interest Rate Total			0				0				0				(196	)			183				(13	)
Gain (Loss) on Derivatives, Net		$	1,602			$	10,572			$	12,174			$	224			$	1,764			$	1,988

 

(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.

 

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		Nine Months Ended September 30, 2011												Nine Months Ended September 30, 2010
		Realized Gains (Losses)				Unrealized Gains (Losses)				Total				Realized Gains (Losses)				Unrealized Gains (Losses)				Total
Crude Oil
Reclassification of settled contracts included in prior periods mark-to-market adjustment		$	0			$	1,388			$	1,388			$	0			$	4,337			$	4,337
Mark-to-market fair value adjustments			0				4,611				4,611				0				1,068				1,068
Settlement of contracts (a)			(648	)			0				(648	)			(2,328	)			0				(2,328	)
Crude Oil Total			(648	)			5,999				5,351				(2,328	)			5,405				3,077
Natural Gas
Reclassification of settled contracts included in prior periods mark-to-market adjustment			0				(3,173	)			(3,173	)			0				(1,444	)			(1,444	)
Mark-to-market fair value adjustments			0				6,146				6,146				0				5,599				5,599
Settlement of contracts (a)			4,463				0				4,463				2,857				0				2,857
Natural Gas Total			4,463				2,973				7,436				2,857				4,155				7,012
Interest Rate
Reclassification of settled contracts included in prior periods mark-to-market adjustment			0				0				0				0				582				582
Mark-to-market fair value adjustments			0				0				0				0				(43	)			(43	)
Settlement of contracts (a)			0				0				0				(588	)			0				(588	)
Interest Rate Total			0				0				0				(588	)			539				(49	)
Gain (Loss) on Derivatives, Net		$	3,815			$	8,972			$	12,787			$	(59	)		$	10,099			$	10,040

 

(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 September 30, 2010, 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. This interest rate swap expired in November 2010. We used 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 agreed 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 was 4.15%. The fair value of the swap at September 30, 2010 was a liability of $0.2 million. We accounted for the interest rate swap by recording the unrealized and realized gains for the three months and nine months ended September 30, 2010 in Gain on Derivatives, Net on our Consolidated Statement of Operations.

Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was an asset of approximately $11.6 million and a net asset of $2.6 million at September 30, 2011 and December 31, 2010, respectively. Included in the fair value as of September 30, 2011, is a liability of approximately $0.5 million associated with a premium that is due to the counterparty upon settlement of the related contract.

As of September 30, 2011, we had approximately 82.5%, 77.3% and 34.4% of our current oil production on an annualized basis hedged through 2011, 2012 and 2013, respectively, and 79.6%, 74.9% and 88.9% of our current gas production on an annualized basis hedged through 2011, 2012 and 2013, respectively. Our open asset/(liability) financial commodity derivative instrument positions at September 30, 2011 consisted of:

 

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Period		Volume				Put Option				Floor				Ceiling				Swap				Fair Market Value ($ in Thousands)
Oil
2011—Collar			144,000 Bbls			$	0			$	68.54			$	104.69			$	0			$	240
2012—Collar			540,000 Bbls				0				67.10				112.03				0				1,491
2013—Collar			240,000 Bbls				0				70.50				120.00				0				1,055
			924,000 Bbls																			$	2,786
Natural Gas
2011—Swap			510,000 Mcf			$	0			$	0			$	0			$	4.82			$	458
2011—Put Spread			180,000 Mcf				3.68				5.00				0				0				200
2011—Three Way Collar			180,000 Mcf				4.00				4.75				5.25				0				72
2011—Put			180,000 Mcf				0				8.00				0				0				752
2011—Collar			480,000 Mcf				0				4.91				6.58				0				458
2012—Swap			1,320,000 Mcf				0				0				0				5.58				1,828
2012—Swaption			600,000 Mcf				0				0				0				5.25				96
2012—Three Way Collar			1,440,000 Mcf				4.00				4.88				5.55				0				575
2012—Collar			2,400,000 Mcf				0				4.88				6.25				0				1,833
2013—Swap			720,000 Mcf				0				0				0				4.75				131
2013—Three Way Collar			720,000 Mcf				4.00				5.00				5.85				0				286
2013—Put			840,000 Mcf				5.00				0				0				0				38	a
2013—Collar			4,560,000 Mcf				0				4.96				6.07				0				2,097
			14,130,000 Mcf																			$	8,824

 

a	Includes liability of approximately $0.5 million for premium due upon settlement of contract.

 

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The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010 is summarized below ($ in thousands):

 

		September 30, 2011				December 31, 2010
Short-Term Derivative Assets:
Crude Oil – Collars		$	1,359			$	0
Natural Gas – Swaps			1,829				519
Natural Gas – Swaption			72				0
Natural Gas – Three Way Collar			504				0
Natural Gas – Collars			1,833				1,132
Natural Gas – Puts			752				2,464
Natural Gas – Put Spread			200				449
Total Short –Term Derivative Assets		$	6,549			$	4,564
Long-Term Derivative Assets:
Crude Oil – Collars		$	1,426			$	63
Natural Gas – Swaps			588				663
Natural Gas – Swaption			24				0
Natural Gas – Collars			2,555				724
Natural Gas – Three Way Collar			430				0
Natural Gas – Putsa			38				0
Total Long – Term Derivative Assets		$	5,061			$	1,450
Total Derivative Assets		$	11,610			$	6,014
Short-Term Derivative Liabilities:
Crude Oil – Collars		$	0			$	(1,850	)
Natural Gas – Collars			0				(10	)
Total Short – Term Derivative Liabilities		$	0			$	(1,860	)
Long-Term Derivative Liabilities:
Crude Oil – Collars		$	0			$	(1,429	)
Natural Gas – Collars			0				(88	)
Total Long – Term Derivative Liabilities		$	0			$	(1,517	)
Total Derivative Liabilities		$	0			$	(3,377	)

 

a	Includes liability of approximately $0.5 million for premium due upon settlement of contract.

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. 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. This fair value may be different from the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers for such assets or liabilities. There are three levels of 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 are as follows:

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

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.

 

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During the three and nine months ended September 30, 2011, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value ($ in thousands):

 

						Fair Value Measurements at September 30, 2011 Using:
		Total Carrying Value as of September 30, 2011				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Derivatives(a) – commodity swaps and collars		$	11,610			$	0			$	11,610			$	0
Asset Retirement Obligations		$	(18,338	)		$	0			$	0			$	(18,338	)

 

(a)	All of our derivatives are classified as Level 2 measurements. For information regarding their classification on our Consolidated Balance Sheets, please refer to the table on page 14 of this report.

The value of our oil derivatives are collar contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair value of our oil derivatives as of September 30, 2011 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the collar contracts. The implied rates of volatility inherent in our collar contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of puts, swaps, collars and three way collar contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of September 30, 2011 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the collar and three way collar contracts. The implied rates of volatility inherent in our collar and three way collar contracts were determined based on market-quoted volatility factors. 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; fixed and variable plugging costs; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. Refer to Note 2, Future Abandonment Cost, of our Consolidated Financial Statements for further information on asset retirement obligations, which include a reconciliation of the beginning and ending balances that represent the entirety of our Level 3 fair value measurements.

8. INCOME TAXES

We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.

Income tax included in continuing operations was as follows ($ in thousands):

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Income Tax (Expense) Benefit		$	4,368			$	(6,610	)		$	6,866			$	(8,034	)
Effective Tax Rate			34.8	%			40.7	%			35.9	%			39.0	%

For the three and nine months ended September 30, 2011, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to state taxes, which was in part offset by downward revisions in relation to permanent differences, changes to estimated future state rates and state net operating loss carryforward true-ups. For the

 

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three and nine months ended September 30, 2010, our overall effective tax rate on pretax losses from continuing operations was different than the statutory rate of 35% due primarily to an adjustment to the tax basis as it relates to certain non-controlling interest components.

During the three and nine-month periods ended September 30, 2011, we paid approximately $49,000 in income taxes. No income tax payments were made during the three and nine months ended September 30, 2010.

9. CAPITAL STOCK

We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of September 30, 2011 and December 31, 2010, we had 44,342,522 and 44,306,677 shares of common stock outstanding, respectively.

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 used a portion of the proceeds of the offering to fully repay outstanding borrowings under our Senior Credit Facility and used the remaining net proceeds to fund a portion of our capital expenditure program for 2010 and for other general corporate purposes.

10. EMPLOYEE BENEFIT AND EQUITY PLANS

401(k) Plan

We sponsor a 401(k) plan for eligible employees who have satisfied minimum age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan were $0.1 million and $0.3 million for the three and nine months ended September 30, 2011, respectively, and $0.1 million and $0.2 million for the three and nine months ended September 30, 2010.

Equity Plans

We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations 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.

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, as amended (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 Internal Revenue Code or covered employees, are intended 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 closing price of our common stock on the NASDAQ Global Market on the date of the grant. All outstanding stock options have been awarded with five or ten year expiration dates at an exercise price equal to our closing price on the NASDAQ Global Market on the day the award was granted. 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

Stock options represent the right to purchase shares of common 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.

 

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During the nine-month period ended September 30, 2011, the Compensation Committee awarded options to purchase a total of 3,500 shares of our common stock to one employee. During the nine-month period ended September 30, 2010, the Compensation Committee awarded options to purchase a total of 36,935 shares of our common stock to five directors. The nonqualified stock options granted to the one employee have an exercise price equal to the closing price of our common stock on the NASDAQ Global Market on the date of grant, and vest and become exercisable in one-third increments on the first, second and third year anniversaries of the date of the grant. The nonqualified stock options granted to the 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 the grant. All options will vest and become immediately exercisable upon a “change in control”, as such term is defined in the Plan.

A summary of the stock option activity is as follows:

 

		Shares				Weighted Average Exercise Price				Weighted Average Remaining Term (in years)				Aggregate Intrinsic  Value (in thousands)
Outstanding on December 31, 2010			826,511			$	12.50
Granted			3,500				11.87
Exercised			(122,482	)			9.48
Cancelled/Expired/Forfeited			(25,002	)			10.89
Options Outstanding on September 30, 2011			682,527			$	13.10				5.1			$	1,386
Options Exercisable on September 30, 2011			569,743			$	13.49				5.2			$	1,208

Stock-based compensation expense relating to stock options for the three and nine months ended September 30, 2011 totaled $0.1 million and $0.6 million, respectively, compared to expense for the three and nine months ended September 30, 2010 of $0.1 million and $0.8 million, respectively. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. The intrinsic value of stock options exercised for the three and nine months ended September 30, 2011 was $0.3 million. The total tax benefit for the three and nine months ended September 30, 2011 was $0.2 million and $0.3 million, respectively. There were no stock option exercises during the three and nine months ended September 30, 2010.

A summary of the status of our issued and outstanding stock options as of September 30, 2011 is as follows:

 

		Outstanding												Exercisable
Exercise Price		Number Outstanding At 9/30/11				Weighted-Average Remaining Contractual Life (Years)				Weighted-Average Exercise Price				Number Exercisable At 9/30/11				Weighted-Average Exercise Price
$9.99			239,499				6.1								239,499			$	9.99
$9.50			100,000				6.1								100,000			$	9.50
$13.56			20,700				3.9								20,700			$	13.56
$22.34			38,000				5.2								38,000			$	22.34
$23.88			75,000				1.6								75,000			$	23.88
$23.28			4,000				1.8								4,000			$	23.28
$19.92			22,000				1.1								22,000			$	19.92
$21.10			30,000				1.9								30,000			$	21.10
$5.04			46,041				7.6								30,696			$	5.04
$10.42			29,548				8.7								9,848			$	10.42
$13.01			18,526				4.0								0			$	0
$12.50			19,139				4.2								0			$	0
$12.30			36,574				1.4								0			$	0
$11.87			3,500				4.6								0			$	0
			682,527				5.1			$	13.10				569,743			$	13.49

The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at September 30, 2011 were 5.1 years and $1.4 million, respectively. The weighted average remaining contractual term and the aggregate intrinsic value

 

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for options exercisable at September 30, 2011 were 5.2 years and $1.2 million, respectively. As of September 30, 2011, unrecognized compensation expense related to stock options totaled approximately $0.2 million, which will be recognized over a weighted average period of 1.4 years.

Stock Appreciation Rights

Stock appreciation rights (“SARs”) represent the right to receive cash in the future equivalent to the difference between the fair market value at the time of exercise and the exercise price. As of September 30, 2011, we had 20,500 SARs outstanding that were granted in February 2008, which have an exercise price of $13.56, the closing price of our common stock on the NASDAQ Global Market on the date of the grant, and vested and became exercisable in February 2011. The outstanding SARs may only be exercised for cash settlement. Compensation expense relating to SARs for the three and nine months ended September 30, 2011 totaled expense of $37,000 and a credit of $12,000, respectively compared with expense of $0.2 million for the same periods in 2010. The expense related to SARs was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense.

 

		Outstanding																Exercisable
Strike Price		Number of SARs Granted				SARs Forfeited or Cancelled				SARs Outstanding				Weighted-Average Remaining Contractual Life (Years)				SARs				Weighted-Average Exercise Price
$    13.56			109,500				(89,000	)			20,500				6.4				20,500			$	13.56

As of September 30, 2011, the aggregate intrinsic value of SARs outstanding was $0. There were no SARs exercises during the nine-month period ended September 30, 2011. All of our SARs were granted in 2008 with grant date fair values of $6.91 per share based on a weighted average exercise price of $13.56 per share, expected annual dividends per share of 0.0%, expected life in years of 6.5, expected volatility of 45.1% and a risk-free interest rate of 4.1%. 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 SARs. The average expected life has been determined using the “simplified method” in which the average expected life of the SARs is equal to the average of the term of the SARs 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 do not use an estimated forfeiture rate as all awards are expected to vest and become exercisable.

Restricted Stock and Phantom Stock Awards

During the nine-month period ended September 30, 2011, the Compensation Committee issued an aggregate of 164,649 shares of restricted common stock to 12 employees and five directors. During the nine-month period ended September 30, 2010, the Compensation Committee issued an aggregate of 386,419 shares of restricted stock to 22 employees. In addition, during the first quarter of 2011 the Compensation Committee issued 16,235 phantom stock awards to five directors, which can only be settled in cash and have not been included in our count of outstanding common stock. The shares granted under these awards are subject to time vesting and performance-based vesting. The performance-based vesting is generally dictated by cumulative three-year targets for consolidated company production and discretionary cash flow per weighted-average outstanding share. The shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date through the third anniversary of the grant date. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. Upon a “change in control” of us, as such term is defined in the Plan, all restrictions will immediately lapse with respect to the greater of: (i) 50% of the maximum number of shares or (ii) the number of shares that would be awarded if the applicable performance-based goals and the extent such goals were satisfied are measured as of the date of the change in control. Shares that do not become vested, as defined in the Plan, will be forfeited and the recipient will cease to have any rights of a stockholder with respect to such forfeited shares.

Compensation expense associated with restricted stock awards is recognized on a straight-line basis over the vesting period and is periodically adjusted for estimated forfeiture rates and estimated satisfaction of performance-based goals. Compensation expense associated with restricted stock awards totaled $0.2 million and $0.8 million for the three and nine-month periods ended September 30, 2011, respectively, and a credit of $21,000 and expense of $0.2 million for the same periods in 2010, respectively. As of September 30, 2011, total unrecognized compensation cost related to restricted common stock grants was approximately $1.5 million,

 

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which will be recognized over a weighted average period of 2.1 years.

A summary of the restricted stock activity for the nine months ended September 30, 2011 is as follows:

 

		Number of Shares				Weighted Average  Grant Date Fair Value
Restricted stock awards, as of December 31, 2010			814,965			$	11.01
Awards			164,649				11.82
Forfeitures			(251,286	)			11.38
Restrictions released			0				0
Restricted stock awards, as of September 30, 2011			728,328			$	11.04

A summary of the phantom stock activity for the nine months ended September 30, 2011 is as follows:

 

		Number of Shares				Weighted Average  Grant Date Fair Value
Phantom stock awards, as of December 31, 2010			0			$	0
Awards			16,235				12.32
Forfeitures			0				0
Restrictions released			0				0
Phantom stock awards, as of September 30, 2011			16,235			$	12.32

11. COMMITMENTS AND CONTINGENCIES

Legal Reserves

We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.

Our reserve for legal accruals relating to legal costs and expenses totaled approximately $0.1 million and $0.2 million as of September 30, 2011 and December 31, 2010, respectively. The accrual of reserves for legal matters is included in Accrued Expenses on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently 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 our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

Settlement Agreement – Class Action Lawsuit in Westmoreland County, Pennsylvania

On May 13, 2011, we, together with our wholly owned subsidiary, Rex Energy I, LLC, entered into a Settlement Agreement with respect to the legal proceedings with landowners in Westmoreland County, Pennsylvania described in our Annual Report on Form 10-K for the year ended December 31, 2010.

Plaintiffs in the case, Clyde J. and Janelle Snyder, William L. Snyder, III and Ray F. and Sandra K. White, commenced the proceedings in July 2009 on behalf of themselves and other landowners in Westmoreland County, Pennsylvania. Plaintiffs alleged, among other things, that we entered into valid and binding oil and gas leases with them in 2008 for which pre-paid rental and bonus payments had not been made. We denied the validity of the leases and all liability for payments. On July 15, 2011, the court approved the Settlement Agreement, pursuant to which we offered each eligible class member an oil and gas lease, in a form agreed to by the parties, with a prepaid rental of $2,500 per acre for a five-year term with a 15% royalty. We also agreed to pay $30,000 to plaintiffs’ attorneys for the anticipated expenses of administration of the Settlement Agreement. Additionally, we deposited $2,500,000 into a fund for distribution to class members and for attorney’s fees, costs and expenses of counsel for the class. The final order regarding the Settlement Agreement dismissed all claims against us with prejudice and without any admission of liability, and provided a release by all class members of all claims against us in connection with the litigation.

 

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Other than as described above, during the three and nine months ended September 30, 2011, there were no material developments with respect to legal proceedings by or against us.

Acreage Bonus Payments

At September 30, 2011, we had three installment payment commitments on mineral interests that were previously leased. The first commitment provides that we pay a total commitment of $0.4 million, in 2012. The second commitment requires that we pay $0.6 million in 2012. The third commitment requires that we pay $350 per mineral acre for 305 net acres, or $0.1 million, in 2011 and 2012 for a total commitment of $0.2 million. We have recorded $1.1 million as a short-term liability in Accrued Expenses on our Consolidated Balance Sheets. The long-term portion of these payments was recorded in Other Deposits and Liabilities on our Consolidated Balance Sheets.

Environmental

Due to the nature of the oil and natural gas 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 of our policies and properties to identify changes in the environmental risk profile. In these reviews we 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 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. As of September 30, 2011, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

At September 30, 2011, we had posted $0.8 million in various letters of credit to secure our drilling and related operations.

Lease Commitments

At September 30, 2011, we had lease commitments for five different office locations and a house. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and nine months ended September 30, 2011 was $0.1 million and $0.3 million, respectively, as compared to income of $0.1 million and expense of $0.3 million for the three and nine months ended September 30, 2010, respectively. During the first quarter of 2010 we closed our Canonsburg, Pennsylvania office and subsequently recognized, as General and Administrative Expense, the present value of all future lease payments, which approximated $0.3 million. During the second quarter of 2010 we subleased our Canonsburg office location and recognized a credit to General and Administrative Expense of approximately $0.3 million. Lease commitments by year for each of the next five years are presented in the table below ($ in thousands):

 

2011		$	151
2012			602
2013			574
2014			104
2015			44
Thereafter			0
Total		$	1,475

 

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Capacity Reservation

In relation to our formation of Keystone Midstream Services, LLC (“Keystone Midstream”) (see Note 13, Variable Interest Entities, Note 14, Equity Method Investments, to our Consolidated Financial Statements), we entered into a capacity reservation arrangement with Keystone Midstream to ensure sufficient capacity at the cryogenic gas processing plant owned by Keystone Midstream to process our produced natural gas. Under the terms of the arrangement, we have reserved 14 net Mmcfe of processing capacity per day for the first year, effective in February 2011, and 28 net Mmcfe of processing capacity for the subsequent nine years, or through January 2020. If we do not meet our capacity reservation volumes, we are obligated to pay $0.30/Mcfe per day for the difference between actual processed volumes and the reservation volume. During the three and nine months ended September 30, 2011, we incurred charges for approximately $0 and $0.1 million, respectively, in relation to the capacity reservation. In the event that we do not process any gas through the cryogenic gas processing plant we may be obligated to pay approximately $0.4 million for the remainder of 2011 and approximately $3.1 million for each year in which 28 net Mmcfe of processing capacity is reserved. As of September 30, 2011, our production has increased to levels above the capacity reservation levels.

Operational Commitments

Pursuant to agreements reached during the fourth quarter of 2010 and the first quarter of 2011, we have contracted drilling rig services on two rigs to support our Butler County, Pennsylvania operations. The minimum cost to retain these rigs would require payments of approximately $0.3 million in 2011, $1.1 million in 2012 and $0.1 million 2013, which is consistent with our 70% working interest in this project area. In addition, during the first quarter of 2011 we came to terms on contracted completion services in Butler County, Pennsylvania. The minimum cost to retain the completion services is approximately $2.5 million in 2011, $8.4 million in 2012 and $2.1 million in 2013, which is consistent with our 70% working interest in this project area.

Natural Gas Sales Agreement

Our wholly-owned subsidiary, R.E. Gas Development, LLC entered into a long-term natural gas sales agreement with BP Energy Company (“BP Energy”) whereby we will supply natural gas to BP Energy at certain delivery points in Pennsylvania. The term of the sales agreement will end upon the earlier of (i) the termination of a service agreement, dated June 23, 2009, between BP Energy and Dominion Transmission, Inc., or (ii) December 31, 2022, unless earlier terminated under certain conditions specified in the sales agreement. During the term of the sales agreement, we are obligated to provide to BP Energy, and BP Energy is obligated to purchase from us, a minimum monthly volume of natural gas equivalent to 17,500 MMBtu of natural gas per day from March 1, 2012 to December 31, 2012 and 59,500 MMBtu per day after January 1, 2013. On all volumes delivered, and on any shortfall between volumes delivered and the minimum monthly quantity, we are obligated to pay a marketing fee of $0.025 per MMBtu and the DTI demand charge of $0.1415 per MMBtu. Minimum obligations under the sales agreement for the next five years are as follows ($ in thousands):

 

2011		$	—
2012			892
2013			3,616
2014			3,616
2015			3,616
Thereafter			25,312
Total		$	37,051

In connection with the entry into the sales agreement, we concurrently entered into a guaranty agreement whereby we have guaranteed the payment of obligations under the sales agreement up to a maximum of $50.0 million.

Other

In addition to the Asset Retirement Obligation discussed in Note 2, Future Abandonment Costs, to our Consolidated Financial Statements, we have withheld from distributions to certain other working interest owners amounts to be applied towards their share of those retirement costs. These amounts totaled $0.3 million at September 30, 2011 and December 31, 2010 and are included in Other Liabilities on our Consolidated Balance Sheets.

12. EARNINGS PER COMMON SHARE

Basic income per common share is calculated based on the weighted average number of common shares outstanding at the end

 

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of the period. Diluted income per common share includes the assumed exercise of stock options, given that the hypothetical effect is not anti-dilutive. Due to our net loss from continuing operations for the three and nine-month periods ended September 30, 2011, we excluded all 682,527 outstanding stock options because the effect would have been anti-dilutive to the computations. Stock options of 727,938 for the three-month period ended September 30, 2010 and stock options of 694,331 for the nine-month period ended September 30, 2010 were outstanding but not included in the computations of diluted net income per share because the grant prices were greater than the average market price of the common shares, which has anti-dilutive effect on the computation. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):

 

		Three Months  Ended September 30,								Nine Months Ended September 30, 2011
		2011				2010				2011				2010
Numerator:
Net Income (Loss) Attributable to Rex Energy		$	(8,190	)		$	9,628			$	(12,251	)		$	12,550
Denominator:
Weighted Average Common Shares Outstanding - Basic			44,384				44,051				44,353				43,409
Effect of Dilutive Securities:
Employee Stock Options			—				52				—				86
Weighted Average Common Shares Outstanding - Diluted			44,384				44,103				44,353				43,495
Earnings per Common Share:
Basic — Net Income (Loss) Attributable to Rex Common Shareholders		$	(0.18	)		$	0.22			$	(0.28	)		$	0.29
Diluted — Net Income (Loss) Attributable to Rex Common Shareholders		$	(0.18	)		$	0.22			$	(0.28	)		$	0.29

13. VARIABLE INTEREST ENTITIES

Keystone Midstream Services, LLC

In December 2009, our wholly owned subsidiary, R.E. Gas Development, LLC (“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. As of June 30, 2010, R.E. Gas owned a 40% membership interest in Keystone Midstream and the remaining 60% membership interest was owned by Stonehenge, which also serves as the operator of the entity. At such time, we were considered the primary beneficiary of Keystone Midstream and were thus required to consolidate the operations of the entity.

On September 30, 2010, we sold 30% of our interest in Keystone Midstream to Sumitomo, decreasing our ownership of the entity to 28% and triggering a reevaluation of the consolidation analysis. Due to our decreased ownership in Keystone Midstream and our decreased ownership of the Butler County, Pennsylvania assets to be serviced by Keystone Midstream (see Note 3, Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements), we no longer have the power to direct the activities that most significantly impact the entity’s economic performance. Thus, we are no longer considered the primary beneficiary of Keystone Midstream and deconsolidated the operations of the entity as of September 1, 2010.

NorthStar #3, LLC

In August 2011, R.E. Gas and NorthStar Water Management formed NorthStar #3, LLC to construct, own and operate a water disposal well in Mahoning County, Ohio. As of September 30, 2011, R.E. Gas owned a 49% membership interest in NorthStar #3, LLC and the remaining 51% membership interest was owned by NorthStar Water Management, which also serves as the operator of the entity. NorthStar #3, LLC was determined to be a variable interest entity because the total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated support. The initial equity investment in the entity totaled $1,000. To supplement the operations of NorthStar #3, LLC, the entity entered in to a promissory note with us of up to $3.5 million.

We are considered the primary beneficiary of the entity and have consolidated its financial results. To be considered the primary beneficiary, a member must have the power to direct the activities that most significantly impact the entity’s performance and have a significant variable interest that carries with it the obligation to absorb the losses or the right to receive benefits. The activities that most significantly impact the entity’s economic performance relate to the drilling of a successful disposal well with ample capacity and the ongoing operation of the well. Per the membership agreement, we hold a first right of refusal on all capacity rights for the disposal well, giving us the ability to make decisions regarding the operation and capacity of the well based on market conditions and, thus, the ability to direct the activities that most significantly impact the economic performance of the entity. We hold a significant variable interest in the entity in the form of our 49% membership interest and the $3.5 million promissory note. We have no recourse to recover the amount of the promissory note in the event that the disposal well is unsuccessful, leaving us with the obligation to absorb the losses. Upon success of the disposal well, we will initially have the right to approximately 87.3% of the available cash at the end of the period which covers the repayment of the note and our membership interest.

 

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As of September 30, 2011, we contributed $490 in capital to NorthStar #3, LLC. As of September 30, 2011, the carrying amount and classification of NorthStar #3, LLC assets and liabilities as consolidated into our financial statements were as follows, with no restrictions or obligations to use certain assets to settle associated liabilities (NorthStar #3, LLC did not exist as of September 30, 2010):

 

		September 30, 2011 (in thousands)
ASSETS
Cash and Cash Equivalents		$	656
Wells and Facilities in Progress			1,681
Total Assets		$	2,337
LIABILITIES
Accounts Payable		$	169
Total Liabilities		$	169

14. EQUITY METHOD INVESTMENTS

RW Gathering, LLC

Pursuant to the terms of the Williams PEA, we and Williams agreed to form RW Gathering, LLC (“RW Gathering”), to own any gas-gathering assets that we agree to jointly construct in order to facilitate the development of our Project Area. The initial members of RW Gathering were Williams and us, each owning an equal interest in the company. On September 30, 2010, pursuant to the Sumitomo PEA, we sold 20% of our interest in RW Gathering to Sumitomo, decreasing our ownership in RW Gathering to 40% (for additional information, see Note 3, Business and Oil and Gas Property Acquisitions and Dispositions, to our Consolidated Financial Statements). Williams is the manager and operator of RW Gathering.

We recorded our investment in RW Gathering of approximately $14.0 million and $6.4 million as of September 30, 2011 and December 31, 2010, respectively, on our Consolidated Balance Sheets as Equity Method Investments. During the first nine months of 2011 we contributed approximately $6.8 million in cash to RW Gathering to support current pipeline and gathering line construction, compared with $4.1 million for the same period in 2010. RW Gathering recorded net losses from continuing operations of $0.3 million and $0.6 million for the three and nine months ended September 30, 2011, respectively, as compared to net losses from continuing operations of $28,000 and $0.1 million for the three and nine months ended September 30, 2010, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and depreciation expense. Our share of the net loss is recorded on the Statements of Operations as Loss on Equity Method Investments.

During the three and nine months ended September 30, 2011, we incurred approximately $0.3 million and $0.6 million, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC. During the three and nine months ended September 30, 2010, we incurred approximately $0.1 million and $0.2 million, respectively, in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of September 30, 2011 and December 31, 2010, there were no receivables due from RW Gathering to us. At September 30, 2011, we recorded a payable due to RW Gathering in the amount of approximately $1.1 million for capital needs of the entity. There were no payables due as of December 31, 2010.

Keystone Midstream

Under the equity method, we recorded our investment in Keystone Midstream of approximately $23.2 million and $12.0 million as of September 30, 2011 and December 31, 2010, respectively, on our Consolidated Balance Sheets as Equity Method Investments. During the first nine months of 2011 and 2010, we contributed approximately $11.2 million, of which $7.7 million had been paid as of September 30, 2011, and $7.3 million, respectively, to Keystone Midstream to primarily support the construction of the cryogenic gas processing plants. Keystone Midstream recorded net income from operations of $0.7 million and $0.2 million for the three and nine months ended September 30, 2011, respectively, as compared to net losses of $0.1 million and $0.3 million for the three and nine-month periods ended September 30, 2010, respectively.

Prior to September 1, 2010, we consolidated the results of Keystone Midstream and Stonehenge’s share of net loss was recorded as Net Loss Attributable to Noncontrolling Interests. Since September 1, 2010, we have recorded our share of net losses

 

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related to Keystone Midstream as Loss on Equity Method Investments on our Consolidated Statements of Operations. Our share of the losses are primarily due to project management costs, general and administrative expenses and DD&A expenses.

During the three and nine months ended September 30, 2011, we incurred approximately $1.4 million and $3.3 million, respectively, in transportation, processing and capacity reservation expenses that were charged to us from Keystone Midstream. During the three and nine months ended September 30, 2010, we incurred approximately $0.1 million in transportation expenses that were charged to us from Keystone Midstream. Prior to September 1, 2010, the charges incurred were eliminated in consolidation. Since September 1, 2010, such transportation charges have been recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations. As of September 30, 2011 and December 31, 2010, there was approximately $0.5 million and $0.1 million in payables due from us to Keystone Midstream for gas processing services provided during the respective periods. Additionally, as of September 30, 2011, we had approximately $3.5 million payable to Keystone Midstream for capital contributions due from us. As of September 30, 2011 and December 31, 2010, there were no receivables due to us from Keystone Midstream. For additional information on our relationship and transactions with Keystone Midstream, see Note 13, Variable Interest Entities, to our Consolidated Financial Statements.

15. IMPAIRMENT EXPENSE

For the three and nine months ended September 30, 2011, we incurred approximately $2.4 million and $14.2 million in impairment expenses, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first nine months of 2011 is primarily related to one well located in the DJ Basin and the surrender or expiration of several unproved leases in the DJ Basin. The well is located on an outlying tract of acreage from our core operations that was drilled under the terms of a farm-out agreement. While the well is commercially productive it was proven to be substantially impaired based upon several factors, including future economic estimates. The well is not located near any of our core operations. In addition, we conducted a 3-D seismic review for our DJ Basin operations, the results of which contributed to our decision not to renew certain leaseholds in the region. As of September 30, 2011, we continued to carry the costs of undeveloped and developed properties in the DJ Basin of approximately $25.5 million on our Consolidated Balance Sheet. Of this amount, approximately $23.9 million is related to undeveloped properties, which equates to approximately $600 per net acre. Recent leasing and operational activity in the area has provided support for the current carrying value of our undeveloped properties in the DJ Basin. In addition to the impairment related to our DJ Basin assets, we incurred approximately $1.6 million in impairment expense related to a refrigeration plant in the Appalachian Basin which was formerly in use before the commencement of operations at the Sarsen Plant, our jointly owned cryogenic natural gas processing plant in Butler County, Pennsylvania. With larger scale gas processing capabilities in the region there is no further value for the refrigeration plant.

For the three and nine months ended September 30, 2010, we incurred approximately $2.4 million and $3.6 million in impairment expenses, respectively. These expenses were incurred primarily in relation to leasehold expirations in the Appalachian Basin. We actively pursue trade partners for undeveloped acreage in our portfolio for which we do not have current development plans whereby we can obtain undeveloped acreage that is more in line with our future development plans.

16. EXPLORATION EXPENSE

For the three and nine months ended September 30, 2011, we incurred approximately $30.6 million and $33.8 million in exploration expenses, respectively. Approximately $30.5 million of this expense is related to unsuccessful exploratory projects in the DJ Basin. The remaining amounts were incurred due to geological and geophysical type expenditures including 2-D and 3-D seismic operations and delay rental payments. For the three and nine months ended September 30, 2010, we received a credit of $0.5 million and incurred expense of $3.0 million, respectively. The credit received during the third quarter of 2010 was primarily due to reimbursements in relation to our joint venture with Sumitomo. The expense for the nine-month period was related to geological and geophysical type expenditures and delay rental payments.

17. SUBSEQUENT EVENTS

Management Changes

On October 10, 2011, we appointed Thomas C. Stabley as our Chief Executive Officer, replacing Lance T. Shaner, who had been serving as our interim President and Chief Executive Officer since June 3, 2011. Mr. Shaner stepped down from the interim positions effective October 10, 2011, but remains Chairman of the Board of Directors. Mr. Stabley will continue to serve as our Interim Chief Financial Officer. Also in connection with his appointment as Chief Executive Officer, Mr. Stabley has been elected to serve on our Board of Directors. As an executive of the company, Mr. Stabley will not serve on any committee and will receive no additional compensation for his service on the Board of Directors.

 

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Also on October 10, 2011, we appointed Patrick M. McKinney to the position of President and Chief Operating Officer. Mr. McKinney had been serving as Executive Vice President and Chief Operating Officer of the company since May 2010.

Litigation Related to Proposed Oil and Gas Leases in Clearfield County, Pennsylvania

In late October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale Case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale Case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them. 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. The lawsuit was only recently filed and the litigation recently commenced. As such, we are in the process of gathering data and preparing our defense and we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses.

 

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Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended December 31, 2010 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

We use a variety of financial and operational measurements at interim periods to analyze our performance. These measurements include an analysis of production and sales revenue for the period; EBITDAX, a non-GAAP financial measurement; lease operating expenses per Mcf equivalent (“LOE per Mcfe”); and general and administrative (“G&A”) expenses per Mcfe.

Results of Continuing Operations

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
		2011				2010				2011				2010
Production:
Oil and Condensate (Bbl)			181,027				175,869				523,946				514,524
Natural Gas (Mcf)			2,583,768				774,154				5,768,163				2,109,086
Natural Gas Liquids (Bbl)			59,869				7,073				136,876				16,944
Total (Mcfe)(a)			4,029,144				1,871,806				9,733,095				5,297,894
Average daily production:
Oil and Condensate (Bbl)			1,968				1,912				1,919				1,885
Natural Gas (Mcf)			28,084				8,415				21,129				7,726
Natural Gas Liquids (Bbl)			651				77				501				62
Total (Mcfe)(a)			43,795				20,346				35,652				19,406
Average sales price:
Oil and Condensate (per Bbl)		$	86.08			$	72.60			$	91.68			$	74.11
Natural Gas (per Mcf)		$	4.44			$	4.49			$	4.55			$	4.67
Natural Gas Liquids (per Bbl)		$	54.69			$	24.53			$	53.48			$	29.07
Total (per Mcfe)(a)		$	7.53			$	8.77			$	8.38			$	9.15
Average NYMEX prices(b):
Oil (per Bbl)		$	89.55			$	76.11			$	95.42			$	77.60
Natural Gas (per Mcf)		$	4.06			$	4.24			$	4.21			$	4.54

 

(a)	Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent (“BOE”) to six Mcfe.

(b)	Based upon the average of bid week prompt month prices.

 

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		Production and Revenue by Basin
		For Three Months  Ended September 30,								For Nine Months Ended September 30,
		2011				2010				2011				2010
Appalachian
Revenues – Natural Gas		$	11,484,698			$	3,477,818			$	26,218,329			$	9,843,304
Volumes (Mcf)			2,583,768				774,154				5,768,163				2,109,086
Average Price		$	4.44			$	4.49			$	4.55			$	4.67
Revenues – Condensate		$	35,491			$	5,731			$	51,673			$	5,251
Volumes (Bbl)			478				103				673				107
Average Price		$	74.18			$	55.64			$	76.78			$	49.07
Revenues – Natural Gas Liquids		$	3,274,197			$	173,517			$	7,320,352			$	492,526
Volumes (Bbl)			59,869				7,073				136,876				16,944
Average Price		$	54.69			$	24.53			$	53.48			$	29.07
Average Production Cost per Mcfe(a)		$	1.19			$	1.16			$	1.24			$	1.18
Illinois
Revenues – Oil		$	15,464,384			$	12,762,343			$	47,496,605			$	38,125,606
Volumes (Bbl)			179,436				175,766				517,250				514,417
Average Price		$	86.18			$	72.61			$	91.83			$	74.11
Average Production Cost per Bbl(a)		$	29.75			$	29.42			$	29.31			$	28.70
DJ
Revenues – Oil		$	82,877			$	—			$	484,651			$	—
Volumes (Bbl)			1,113				—				6,023				—
Average Price		$	74.49			$	—			$	80.46			$	—
Average Production Cost per Bbl(a)		$	79.43			$	—			$	54.19			$	—

 

(a)	Excludes ad valorem and severance taxes.

 

		Other Performance Measurements From Continuing Operations
		For Three Months  Ended September 30,								For Nine Months Ended September 30,
		2011				2010				2011				2010
EBITDAX (in thousands)(a)		$	18,796			$	5,739			$	43,356			$	18,182
LOE per Mcfe		$	2.26			$	3.46			$	2.51			$	3.43
G&A per Mcfe		$	1.21			$	2.68			$	2.06			$	2.60

 

(a)	EBITDAX is a non-GAAP measure. EBITDAX is defined on page 36 of this report.

 

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General Overview

Operating revenue for the three and nine months ended September 30, 2011 increased 82.9% and 69.2%, respectively, when compared to the same periods in 2010. This increase is primarily due to the continued success of our Marcellus Shale drilling program. The start-up of our jointly owned cryogenic gas processing plant in Butler County, Pennsylvania increased our available capacity to sell gas and natural gas liquids in the region where we placed into sales 16 new horizontal wells at various points during the first nine months of 2011. Williams, our joint venture partner in Westmoreland and Clearfield Counties, Pennsylvania, placed into service an additional 15 horizontal wells during the first nine months of 2011. The average sales price per Mcfe, which includes the Mcf equivalent of oil and natural gas liquids as defined on page 27, during the three and nine-month periods ended September 30, 2011 was $7.53 and $8.38, respectively, as compared to $8.77 and $9.15 during the comparable periods of 2010. Total production for the three and nine-month periods ended September 30, 2011 increased approximately 115.3% and 83.7%, respectively, when compared to the same periods in 2010. The increase in production can be attributed to the continued success of our Marcellus Shale drilling program in the Appalachian Basin, where production increased approximately 260.5% and 198.2% for the three and nine months ended September 30, 2011, respectively, as compared to the three and nine months ended September 30, 2010, primarily related to the start-up of our jointly owned cryogenic gas processing plant in Butler County, Pennsylvania.

Operating expenses increased $53.0 million for the three-month period ended September 30, 2011 as compared to the same period in 2010 and $76.1 million for the nine-month period ended September 30, 2011 as compared to the same period in 2010. Operating expenses are primarily comprised of: Production and Lease Operating Expenses; G&A Expenses; Exploration Expenses; Impairment Expense; and DD&A Expenses. The increases in operating expenses were largely attributable to the Impairment Expense and Exploration Expense incurred on our properties in the DJ Basin. During the period we impaired one commercially producing well in the DJ Basin and allowed several unproved leases to expire. In addition, we incurred Exploration Expense for three wells that were considered dry holes and other geological and geophysical type costs in the region. Also contributing to the increase were gains recognized during the three and nine-month periods ended September 30, 2010, that were in relation to the closing of the Sumitomo joint venture.

Production and Lease Operating Expenses increased during the three and nine-month periods ended September 30, 2011, as compared to the same period in 2010 primarily due to costs associated with our jointly owned cryogenic gas processing plant in our Butler County, Pennsylvania project area, for which operations commenced during the fourth quarter of 2010. We pay certain fees to process our gas through the plant, which totaled approximately $1.4 million and $3.3 million during the three and nine months ended September 30, 2011. We continue to incur incremental increases in operating expenses as we complete additional wells in the Appalachian Basin and DJ Basin. Despite the overall increase in Production and Lease Operating Expenses, our cost per unit decreased approximately 34.7% and 26.8%, respectively, as compared to the three and nine months ended September 30, 2010. G&A expenses decreased during the three-month period ended September 30, 2011, and increased during the nine-month period ended September 30, 2011, as compared to the same periods in 2010. The decrease during the quarter was primarily due to recruiting costs incurred during the three-month period ended September 30, 2010 in effort to recruit high quality personnel. The increase during the nine-month period was primarily due to severance, personnel adjustments and expenses incurred related to the settlement of our lawsuit in Westmoreland County, Pennsylvania. During the first nine months of 2011, we incurred expenses in relation to severance packages for employees whose employment was terminated during the period. We also recorded an expense of $2.5 million related to the settlement of our lawsuit in Westmoreland County, Pennsylvania.

EBITDAX, is used as a financial measure by us 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 structure;

 

•

The financial performance of our assets and valuation of the entity, without regard to financing methods, capital structure or historical costs basis;

 

•

Our ability to generate cash sufficient to pay interest costs and support our indebtedness; and

 

•

The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX increased approximately $13.1 million to $18.8 million and $25.2 million to $43.4 million for the three and nine-month periods ended September 30, 2011, respectively, as compared to the same periods in 2010. The increase in EBITDAX can be primarily attributed to higher natural gas production and higher average sales prices for oil, resulting in increased operating revenues. These increases were partially offset by an increase in operating expenses, particularly Production and Lease Operating Expense and

 

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G&A Expense.

LOE per Mcfe measures the average cost of extracting oil and natural gas from our basin reserves during the period. This measurement is also commonly referred to in the industry as our “lifting cost”. It represents the average cost of extracting one Mcf of natural gas equivalent from our oil and natural gas reserves in the ground. LOE per Mcfe decreased to $2.26 and $2.51 for the three and nine months ended September 30, 2011, respectively, as compared to $3.46 and $3.43 for the same periods in 2010. G&A expenses per Mcfe measures overhead costs associated with our management and operations. G&A expenses per Mcfe decreased to approximately $1.21 and $2.06 for the three and nine-month periods ended September 30, 2011, respectively, as compared to $2.68 and $2.60 for the same periods in 2010.

 

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Comparison of the Three Months Ended September 30, 2011 to the Three Months Ended September 30, 2010.

Oil and gas revenue for the three-month periods ended September 30, 2011 and 2010 ($ in thousands, except total Mcfe production and price per Mcfe) is summarized in the following table:

 

		For Three Months Ended September 30,
		2011				2010				Change				%
Oil and Gas Revenues:
Oil and condensate sales revenue		$	15,583			$	12,767			$	2,816				22.1%
Oil derivatives realized(a)		$	(5	)		$	(630	)		$	625				99.2%
Total oil and condensate revenue and derivatives realized		$	15,578			$	12,137			$	3,441				28.4%
Gas sales revenue		$	11,485			$	3,478			$	8,007				230.2%
Gas derivatives realized(a)		$	1,607			$	1,050			$	557				53.0%
Total gas revenue and derivatives realized		$	13,092			$	4,528			$	8,564				189.1%
Total natural gas liquid revenue		$	3,274			$	174			$	3,100				1,781.6%
Consolidated sales		$	30,342			$	16,419			$	13,923				84.8%
Consolidated derivatives realized(a)		$	1,602			$	420			$	1,182				281.4%
Total oil and gas revenue and derivatives realized		$	31,944			$	16,839			$	15,105				89.7%
Total Mcfe Production			4,029,144				1,871,806				2,157,338				115.3%
Average Realized Price per Mcfe		$	7.93			$	9.00			$	(1.07	)			(11.9%)

 

(a)	Realized derivatives are included in Other Income (Expense) on our Consolidated Statements of Operations.

Average realized price received for oil and gas during the third quarter of 2011, after the effect of derivative activities, was $7.93 per Mcfe, a decrease of 11.9%, or $1.07 per Mcfe, from the same quarter in 2010. This decrease is primarily due to a higher percentage of sales of natural gas when compared to our sales mix during the third quarter of 2010. The average price for oil and condensate, after the effect of derivative activities, increased 24.7%, or $17.04 per barrel, to $86.05 per barrel. The average price for natural gas, after the effect of derivative activities, decreased 13.4%, or $0.78 per Mcf, to $5.07 per Mcf. Our derivative activities effectively increased net realized price by $0.40 per Mcfe in the third quarter of 2011 and $0.22 per Mcfe in the third quarter of 2010.

Production volumes in the third quarter of 2011 increased 115.3% from the third quarter of 2010. Natural gas production increased approximately 233.8% and our NGL production increased to 59,869 barrels from 7,073 barrels, primarily due to the production in our Marcellus Shale drilling operations in the Commonwealth of Pennsylvania. During the third quarter of 2011 we placed into service three horizontal Marcellus Shale wells in our Butler County region and our joint venture partner, Williams, placed into service six horizontal Marcellus Shale wells in our Westmoreland and Clearfield County regions. Sales at the Sarsen Plant in Butler County averaged approximately 15.5 mmcf of natural gas per day, net, and 650 barrels of NGL’s per day, net, during the third quarter of 2011.

Oil production increased approximately 2.9% in the third quarter of 2011 as compared to the same period in 2010. The natural decline of our Illinois Basin properties was offset by enhancing our secondary waterflood operations in addition to increased oil production from our ASP pilot.

Overall, our production for the three months ended September 30, 2011 averaged 43,795 Mcfe per day, of which 64.1% was attributable to natural gas, 27.0% to oil and 8.9% was a result of natural gas liquids production.

Other operating revenue for the three months ended September 30, 2011 and September 30, 2010 was approximately $0.5 million and $0.4 million, respectively. We generate other operating revenue from various activities such as revenue from the transportation of third-party natural gas and the sale and transfer of water used in the completion of Marcellus Shale wells in the Appalachian Basin.

Production and lease operating expenses increased approximately $2.6 million, or 40.6%, in the third quarter of 2011 from the same period in 2010. The increase in expense is primarily due to commencing operations of a jointly owned cryogenic gas processing plant in Butler County, Pennsylvania during the fourth quarter of 2010 for which we pay certain fees to process our produced gas. These charges totaled approximately $1.4 million for the third quarter of 2011. We also experience incremental increases in operating expenses as additional wells are completed and put into service.

G&A expenses for the third quarter of 2011 decreased approximately $0.1 million, or 2.6%, to $4.9 million from the same period in 2010. G&A expenses decreased during the three-month period ended September 30, 2011, as compared to the same period in 2010 primarily due to recruiting expenses. We incurred higher recruiting expenses during the third quarter of 2010 in relation to our ongoing recruitment of high quality personnel.

Impairment expenses for the third quarter of 2011 and 2010 totaled approximately $2.4 million. Approximately $0.8 million and $0.9 million for the three-month periods ended September 30, 2011 and 2010, respectively, were due to lease expirations in our Marcellus Shale operating region. During the third quarter of 2011 we incurred a charge of approximately $1.6 million due to the impairment of a refrigeration plant in our Butler County, Pennsylvania operating region which was formerly in use before the commencement of operations at the Sarsen Plant. With larger scale gas processing capabilities in the region there is no further value

 

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for the refrigeration plant. We previously recorded an impairment charge on this refrigeration plant during the third quarter of 2010 of approximately $1.6 million based on the fair value calculated on the plant during the Sumitomo joint venture transaction.

Exploration expense for the three months ended September 30, 2011, was approximately $30.6 million. Approximately $30.5 million of this expense is related to unsuccessful exploratory projects in the DJ Basin. The remaining amounts were incurred due to geological and geophysical type expenditures including 2-D and 3-D seismic operations and delay rental payments. For the three months ended September 30, 2010, we received a credit of $0.5 million which was primarily due to reimbursements in relation to our joint venture with Sumitomo.

DD&A expenses for the three months ended September 30, 2011 increased approximately $2.7 million, or 54.2%, from $5.0 million for the same period in 2010. This increase is primarily attributable to the increase in our asset base and associated production when compared to 2010.

Gain on derivatives, net includes a gain of approximately $12.2 million for the third quarter of 2011 as compared to a gain of $2.0 million for the same period in 2010. Changes are attributable 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 end of the last period while gains generally reflect 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.

Net income tax benefit (expense) was a benefit of approximately $4.4 million for the three months ended September 30, 2011 as compared to income tax expense of approximately $6.6 million for the three months ended September 30, 2010. The change was primarily due to the impairment and exploration expenses incurred during the third quarter of 2011.

Net income (loss) attributable to Rex Energy for the third quarter of 2011 was a net loss of approximately $8.2 million, as compared to net income of approximately $9.6 million for the comparable period in 2010 as a result of the factors discussed above.

 

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Comparison of the Nine Months Ended September 30, 2011 to the Nine Months Ended September 30, 2010.

Oil and gas revenue for the nine-month periods ended September 30, 2011 and 2010 ($ in thousands, except total Mcfe production and price per Mcfe) is summarized in the following table:

 

		For Nine Months Ended September 30,
		2011				2010				Change				%
Oil and Gas Revenues:
Oil and condensate sales revenue		$	48,034			$	38,131			$	9,903				26.0%
Oil derivatives realized(a)		$	(648	)		$	(2,328	)		$	1,680				72.2%
Total oil and condensate revenue and derivatives realized		$	47,386			$	35,803			$	11,583				32.4%
Gas sales revenue		$	26,218			$	9,843			$	16,375				166.4%
Gas derivatives realized(a)		$	4,463			$	2,857			$	1,606				56.2%
Total gas revenue and derivatives realized		$	30,681			$	12,700			$	17,981				141.6%
Total natural gas liquid revenue		$	7,320			$	493			$	6,827				1,384.8%
Consolidated sales		$	81,572			$	48,467			$	33,105				68.3%
Consolidated derivatives realized(a)		$	3,815			$	529			$	3,286				621.2%
Total oil and gas revenue and derivatives realized		$	85,387			$	48,996			$	36,391				74.3%
Total Mcfe Production			9,733,095				5,297,894				4,435,201				83.7%
Average Realized Price per Mcfe		$	8.77			$	9.25			$	(0.48	)			(5.2%)

 

(a)	Realized derivatives are included in Other Income (Expense) on our Consolidated Statements of Operations.

Average realized price received for oil and gas during the first nine months of 2011, after the effect of derivative activities, was $8.77 per Mcfe, a decrease of 5.2%, or $0.48 per Mcfe, from the same period in 2010. This decrease is primarily due to a higher percentage of sales of natural gas when compared to our sales mix during the first nine months of 2010. The average price for oil and condensate, after the effect of derivative activities, increased 30.0%, or $20.86 per barrel, to $90.44 per barrel. The average price for natural gas, after the effect of derivative activities, decreased 11.7%, or $0.70 per Mcf, to $5.32 per Mcf. Our derivative activities effectively increased net realized price by $0.39 per Mcfe in the first nine months of 2011 and $0.10 per Mcfe in the same period of 2010.

Production volumes in the first nine months of 2011 increased 83.7% from the first nine months of 2010. Natural gas production increased approximately 173.5% and NGL production increased to 136,876 barrels from 16,944 barrels. During the first nine months of 2011 we placed into service 16 horizontal Marcellus Shale wells in our Butler County region and our joint venture partner, Williams, placed into service 15 horizontal Marcellus Shale wells in our Westmoreland and Clearfield County regions. Sales at the Sarsen plant in Butler County averaged approximately 11.5 mmcf of natural gas per day, net, and 501 barrels of NGL’s per day, net, during the first nine months of 2011.

Oil production increased approximately 1.8% in the first three months of 2011 as compared to the same period in 2010. The natural decline of our Illinois Basin properties was offset by enhancing our secondary waterflood operations in addition to increased oil production from our ASP pilot.

Overall, our production for the nine months ended September 30, 2011 averaged 35,652 Mcfe per day, of which 59.3% was attributable to natural gas, 32.3% to oil and 8.4% was a result of natural gas liquids production.

Other operating revenue for the nine months ended September 30, 2011 and September 30, 2010 was approximately $1.8 million and $0.8 million, respectively. We generate other operating revenue from various activities such as revenue from the transportation of third-party natural gas and the sale and transfer of water used in the completion of Marcellus Shale wells in the Appalachian Basin.

Production and lease operating expenses increased approximately $6.3 million, or 34.5%, in the first nine months of 2011 from the same period in 2010. The increase in expense is primarily due to commencing operations of a jointly owned cryogenic gas processing plant in Butler County, Pennsylvania during the fourth quarter of 2010 for which we pay certain fees to process our produced gas. These charges totaled approximately $3.3 million for the first nine months of 2011. In addition to our gas processing expenses, in the first nine months of 2011 we incurred charges of approximately $0.2 million for the dismantlement of our refrigeration plant in Butler County, Pennsylvania, which was no longer needed in this area to process gas due to the start up of the cryogenic gas processing plant. We also experience incremental increases in operating expenses as additional wells are completed and put into service. During the first nine months of 2011 we placed into service 31 wells. In the Illinois Basin, we have experienced higher than normal costs due to the effects of spring flooding throughout the region.

 

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G&A expenses for the first nine months of 2011 increased approximately $6.3 million, or 45.9%, to $20.1 million from the same period in 2010. G&A expenses increased during the nine-month period ended September 30, 2011, as compared to the same period in 2010 primarily due to recruiting, severance, adjustments to our number of employees and legal fees. We incurred higher recruiting expenses during the second quarter of 2011 in relation to our ongoing recruitment of high quality personnel, which led to an increase in wages and benefits through increased headcounts. Also during the period, we incurred expenses in relation to severance packages for employees whose employment was terminated during the period. We also recorded an expense of approximately $2.5 million related to the settlement of our lawsuit in the Appalachian Basin.

Impairment expenses for the first nine months of 2011 totaled approximately $14.2 million as compared to $3.6 million during the comparable period in 2010. The increase in our impairment expense can be primarily attributed to the surrender or expiration of several leases in our DJ Basin area of operations and the impairment of one well in the basin. A 3-D seismic review was completed for this area of our operations during the first quarter of 2011, the results of which contributed to our decision not to renew certain leaseholds in the basin. The well was evaluated as of June 30, 2011 to determine the recoverability of its carrying costs due to indications that there may be potential impairment, implicated by lower than anticipated production and a lack of firm future development plans in the immediate surrounding area.

Exploration expense for the nine months ended September 30, 2011, was approximately $33.8 million. Approximately $30.5 million of this expense is related to unsuccessful exploratory projects in the DJ Basin. The remaining amounts were incurred due to geological and geophysical type expenditures including 2-D and 3-D seismic operations and delay rental payments. For the nine months ended September 30, 2010, we incurred expense of $3.0 million. The expense for the nine-month period was related to geological and geophysical type expenditures and delay rental payments.

DD&A expenses for the nine months ended September 30, 2011 increased approximately $4.5 million, or 29.6%, from $15.2 million for the same period in 2010. This increase is primarily attributable to the increase in our asset base and associated production when compared to 2010.

Gain on derivatives, net includes a gain of approximately $12.8 million for the first nine months of 2011 as compared to a gain of $10.0 million for the same period in 2010. Changes are attributable 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 end of the last period while gains generally reflect 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.

Net income tax benefit (expense) was a benefit of approximately $6.9 million for the nine months ended September 30, 2011 as compared to income tax expense of approximately $8.0 million for the nine months ended September 30, 2010. The change was due to the net loss during the first nine months of 2011 that was primarily attributable to impairment and exploration expenses incurred during the second and third quarters of 2011.

Net income (loss) attributable to Rex Energy for the first nine months of 2011 was a loss of approximately $12.3 million, as compared to net income of approximately $12.6 million for the comparable period in 2010 as a result of the factors discussed above.

 

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Capital Resources and Liquidity

Our primary needs for cash are for the exploration, development and acquisition of oil and gas properties. During the nine months ended September 30, 2011, $204.4 million of capital was expended on drilling projects, facilities and related equipment and acquisitions of unproved acreage. The capital program was funded by net cash flow from operations and through borrowings under our Senior Credit Facility. Our 2011 capital budget is expected to continue to be funded primarily by cash flow from operations, joint ventures, non-core assets sales and borrowings under our Senior Credit Facility. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a significant drop in commodity prices, particularly natural gas, or 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 also elect to issue additional shares of stock, subordinated notes or other securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.

Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration programs in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flows 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 and exploration programs, we may also suffer a reduction in our operating cash flow and access to funds under the Senior Credit Facility. 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 and borrowings from our Senior Credit Facility have been primarily used to fund exploration and development of our oil and gas interests. As of September 30, 2011, we had $86.0 million available for borrowing under our Senior Credit Facility with a current borrowing base of $240.0 million. We are not restricted as to our borrowings under the Senior Credit Facility; however we are subject to the minimum financial requirements detailed in Note 6, Long-Term Debt and Other Obligations, to our Consolidated Financial Statements.

In addition, we have utilized two joint venture agreements with Sumitomo and Williams to supplement our capital outlay to assist in sustaining our growth prospects. Through the Sumitomo PEA, Sumitomo agreed to pay approximately $58.8 million in drilling expenses in our joint venture areas. As of September 30, 2011, Sumitomo fulfilled its drilling carry obligation in full. In addition to the drilling carry, Sumitomo has also agreed to pay to us a management fee of $150 per acre for leases acquired in our Butler County, Pennsylvania project area.

Financial Condition and Cash Flows for the Nine Months Ended September 30, 2011 and 2010

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

 

		Nine Months Ended September 30, ($ in Thousands)
		2011				2010
Cash flows provided by operations		$	51,057			$	10,601
Cash flows used in investing activities			(196,981	)			(83,340	)
Cash flows provided by financing activities			144,517				131,949
Net increase in cash and cash equivalents		$	(1,407	)		$	59,210

Net cash provided by operating activities increased by approximately $40.5 million in the first nine months of 2011 over the same period in 2010. The increase in 2011 was affected by a combination of factors, but was primarily driven by increased oil and gas production, increased oil prices and an increase in realized gains on natural gas derivatives. Partially offsetting these cash flow increases were increased Production and Lease Operating Expenses and G&A expenses.

Net cash used in investing activities increased by approximately $113.6 million from the first nine months of 2010 to $197.0 million in the first nine months of 2011. This change can be primarily attributed to increased drilling activity, particularly in our Marcellus Shale exploration areas, as compared to 2010, which resulted in placing into service 31 horizontal natural gas wells. This increase was partially offset by a decrease in undeveloped acreage acquisitions of approximately $7.9 million in addition to cash payments received by us for the leasing of acreage in our jointly owned properties with Sumitomo of $3.1 million. During the period, we completed the Sumitomo drilling carry in our Butler County, Pennsylvania project area as well as the Phase I Leasing, which decreased the amount of our restricted cash and increased cash provided by investing activities by approximately $16.1 million.

 

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Net cash provided by financing activities increased by approximately $12.6 million from the first nine months of 2010 to $144.5 million for the first nine months of 2011. The increase is primarily due to the increase in borrowings on our Senior Credit Facility. Partially offsetting this increase was a public offering of common stock in 2010 that netted $80.2 million.

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 the operating cost that we are required to bear for operations, as well as an increase or decrease in revenues.

Critical Accounting Policies and Recently Adopted Accounting Pronouncements

During the quarter ended September 30, 2011, there were no material changes to the critical accounting policies previously reported by us in our Annual Report on Form 10-K for the year ended December 31, 2010. We describe critical recently adopted and issued accounting standards in Item 1. Financial Statements—Note 4, “Recently Issued Accounting Pronouncements.”

Non-GAAP Financial Measures

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, 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 its financial statements, such as our commercial bank lenders.

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash 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 because this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.

We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs. In addition, because we use capital assets, depreciation and amortization are also necessary elements of our costs. Finally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.

To compensate for these limitations, we believe it is important to consider both net incomes determined under GAAP and EBITDAX to evaluate our performance.

 

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

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Net Income (Loss)		$	(8,146	)		$	9,540			$	(12,265	)		$	12,342
Add Back Depletion, Depreciation, Amortization and Accretion			7,679				4,979				19,718				15,211
Add Back Non-Cash Compensation Expense			314				213				1,340				1,168
Add Back Interest Expense(a)			475				626				1,034				1,349
Add Back Impairment Expense			2,379				2,419				14,182				3,567
Add Back Exploration Expenses			30,552				(474	)			33,765				2,972
Less Interest Income			(1	)			(6	)			(10	)			(56	)
Add Back (Less) Loss (Gain) on Disposal of Assets			6				(16,485	)			464				(16,493	)
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives			(10,571	)			(1,764	)			(8,972	)			(10,099	)
Add Back (Less) Noncontrolling Interest Net Loss (Income)			(44	)			88				14				208
Add Back (Less) Income Tax Expense (Benefit)			(4,368	)			6,610				(6,866	)			8,034
Add Back (Less) Equity Method Investment EBITDAX			521				(7	)			952				(21	)
EBITDAX		$	18,796			$	5,739			$	43,356			$	18,182

 

(a)	Includes settlements on interest rate swap for the periods ending September 30, 2010

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

For the three and nine months ended September 30, 2011, the net realized gains on oil and natural gas derivatives were approximately $1.6 million and $3.8 million, respectively, as compared to net realized gains of approximately $0.4 million and $0.5 million for the comparable periods in 2010, respectively. These gains are reported as Gain on Derivatives, Net in our Consolidated Statements of Operations. As of September 30, 2011, we had approximately 82.5%, 77.3% and 34.4% of our current oil production on an annualized basis hedged through 2011, 2012 and 2013, respectively, and 79.6%, 74.9% and 88.9% of our current gas production on an annualized basis hedged through 2011, 2012 and 2013, respectively.

For the three and nine months ended September 30, 2011, the net unrealized gains on oil and natural gas derivatives were $10.6 million and $9.0 million, respectively, as compared to $1.8 million and $10.1 million for the comparable periods in 2010, respectively. The net unrealized gains and losses are reported as Gain on Derivatives, Net in our Consolidated 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 natural gas and oil. We enter into all of our derivatives transactions with two counterparties and have a netting agreement in place with the counterparties. While we do not obtain collateral to support the agreements, we do monitor the financial viability of counterparties and believe our credit risk is 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 derivatives 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 September 30, 2011, refer to Note 7 of our Consolidated Financial Statements, Fair Value of Financial and Derivative Instruments.

 

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Item 3. 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 production through September 30, 2011, we project that a 10% decline in the price per barrel of oil and natural gas liquids and the price per Mcf of gas from the first nine months of the 2011 average would reduce our gross revenues, before the effects of derivatives, for the remaining three months of 2011 by approximately $2.7 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, collars, put spreads, put options, swaptions and three way 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 September 30, 2011, the following commodity derivative contracts were outstanding:

 

Period		Volume				Put Option				Floor				Ceiling				Swap				Fair Market Value ($ in Thousands)
Oil
2011 – Collar			144,000 Bbls			$	0			$	68.54			$	104.69			$	0			$	240
2012 – Collar			540,000 Bbls				0				67.10				112.03				0				1,491
2013 – Collar			240,000 Bbls				0				70.50				120.00				0				1,055
			924,000 Bbls																			$	2,786
Natural Gas
2011 – Swap			510,000 Mcf			$	0			$	0			$	0			$	4.82			$	458
2011 – Put Spread			180,000 Mcf				3.68				5.00				0				0				200
2011 – Three Way Collar			180,000 Mcf				4.00				4.75				5.25				0				72
2011 – Put			180,000 Mcf				0				8.00				0				0				752
2011 – Collar			480,000 Mcf				0				4.91				6.58				0				458
2012 – Swap			1,320,000 Mcf				0				0				0				5.58				1,828
2012 – Swaption			600,000 Mcf				0				0				0				5.25				96
2012 – Three Way Collar			1,440,000 Mcf				4.00				4.88				5.55				0				575
2012 – Collar			2,400,000 Mcf				0				4.88				6.25				0				1,833
2013 – Swap			720,000 Mcf				0				0				0				4.75				131
2013 – Three Way Collar			720,000 Mcf				4.00				5.00				5.85				0				286
2013 – Put			840,000 Mcf				5.00				0				0				0				38	a
2013 – Collar			4,560,000 Mcf				0				4.96				6.07				0				2,097
			14,130,000 Mcf																			$	8,824

 

a	Includes liability of approximately $0.5 million for premium due upon settlement of contract.

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 have used an interest rate swap agreement in the past to manage risk associated with interest payments on amounts outstanding from variable rate borrowings under our Senior Credit Facility. We currently do not have any interest rate derivative contracts in place.

 

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Item 4. Controls And Procedures.

Based on management’s evaluation (with the participation of our Chief Executive Officer and Interim Chief Financial Officer), as of the end of the period covered by this report, our CEO and Interim CFO have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, (the “Exchange Act”)) are effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II

OTHER INFORMATION

 

Item 1.

Legal Proceedings.

The information set forth under the subsections Legal Reserves and Environmental in Note 11, Commitments and Contingencies, to our Consolidated Financial Statements included in Item 1 of Part 1 of this report is incorporated herein by reference.

 

Item 1A.

Risk Factors.

During the quarter ended September 30, 2011, there were no material changes to the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2010.

 

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Item 6.

Exhibits.

EXHIBIT INDEX

 

Exhibit Number		Exhibit Title
3.1		Certificate of Incorporation of Rex Energy Corporation, as amended (incorporated by reference to Exhibit 3.1 to our Annual Report on Form 10-K as filed with the SEC on March 3, 2011).
3.2		Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q as filed with the SEC on May 4, 2011).
10.1		Natural Gas Sales Agreement by and between BP Energy Company and R.E. Gas Development, LLC dated August 9, 2011.*
10.2		Sixth Amendment to Credit Agreement, effective as of August 2, 2011, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto.*
10.3		Seventh Amendment to Credit Agreement, effective as of September 30, 2011, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto.*
31.1		Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act. *
31.2		Certification of Interim 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. *
101.INS**		XBRL Instance Document
101.SCH**		XBRL Taxonomy Extension Schema Document
101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document
101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**		XBRL Taxonomy Extension Label Linkbase Document
101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

 

*	These exhibits are furnished herewith.

**

These exhibits are furnished herewith. In accordance with Rule 406T of Regulation S-T, these exhibits are not deemed to be filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are not deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.

 

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SIGNATURES

Pursuant to the requirements 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.

 

				REX ENERGY CORPORATION (Registrant)
Date: November 8, 2011				By:		/S/    THOMAS C. STABLEY
						Chief Executive Officer
						(Principal Executive Officer)
Date: November 8, 2011				By:		/S/    THOMAS C. STABLEY
						Interim Chief Financial Officer
						(Principal Financial and Accounting Officer)

 

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EXHIBIT INDEX

 

Exhibit Number		Exhibit Title
3.1		Certificate of Incorporation of Rex Energy Corporation, as amended (incorporated by reference to Exhibit 3.1 to our Annual Report on Form 10-K as filed with the SEC on March 3, 2011).
3.2		Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q as filed with the SEC on May 4, 2011).
10.1		Natural Gas Sales Agreement by and between BP Energy Company and R.E. Gas Development, LLC dated August 9, 2011.*
10.2		Sixth Amendment to Credit Agreement, effective as of August 2, 2011, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto.*
10.3		Seventh Amendment to Credit Agreement, effective as of September 30, 2011, among Rex Energy Corporation, as Borrower, KeyBank National Association, as Administrative Agent, and The Lenders Signatory Thereto.*
31.1		Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act. *
31.2		Certification of Interim 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. *
101.INS**		XBRL Instance Document
101.SCH**		XBRL Taxonomy Extension Schema Document
101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document
101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**		XBRL Taxonomy Extension Label Linkbase Document
101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

 

*	These exhibits are furnished herewith.

**

These exhibits are furnished herewith. In accordance with Rule 406T of Regulation S-T, these exhibits are not deemed to be filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are not deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.

 

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