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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

 

x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period ended March 31, 2011

Commission File Number – 0-8041

GEORESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

Colorado		84-0505444
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
110 Cypress Station Drive, Suite 220 Houston, Texas		77090-1629
(Address of principal executive offices)		(Zip code)

(281) 537-9920

(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 registration was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  x    No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ¨    No  ¨

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

 

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

Indicated by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨    No  x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

 

Class of equity		Outstanding at May 5, 2011
Common stock, par value $.01 per share		25,459,930 shares

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TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION

 

Item 1.		Financial Statements.
		Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010.			3
		Consolidated Statements of Income for the Three Months ended March 31, 2011 and 2010.			5
		Consolidated Statement of Equity and Comprehensive Income for the Three Months ended March 31, 2011.			6
		Consolidated Statements of Cash Flows for the Three Months ended March 31, 2011 and 2010.			7
		Notes to Consolidated Financial Statements.			8
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations.			21
Item 3.		Quantitative and Qualitative Disclosures About Market Risk.			29
Item 4.		Controls and Procedures.			30
		PART II – OTHER INFORMATION
Item 1.		Legal Proceedings.			31
Item 1A.		Risk Factors.			31
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds.			31
Item 3.		Defaults Upon Senior Securities.			31
Item 4.		Reserved.			31
Item 5.		Other Information.			31
Item 6.		Exhibits.			32
		Signatures.			33

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GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

 

		March 31,								December 31,
		2011								2010
ASSETS			(unaudited)
Current assets:
Cash		$	42,151							$	9,370
Accounts receivable:
Oil and gas revenues			18,862								17,017
Joint interest billings and other			20,205								16,631
Affiliated partnerships			1,071								969
Notes receivable			120								120
Derivative financial instruments			3,420								4,282
Income taxes receivable			2,372								222
Prepaid expenses and other			3,569								2,645
Total current assets			91,770								51,256
Oil and gas properties, successful efforts method:
Proved properties			351,817								341,582
Unproved properties			43,587								32,403
Office and other equipment			1,152								1,140
Land			146								146
			396,702								375,271
Less accumulated depreciation, depletion and amortization			(74,893	)							(72,380	)
Net property and equipment			321,809								302,891
Equity in oil and gas limited partnerships			2,219								2,272
Derivative financial instruments			647								851
Deferred financing costs and other			2,137								2,420
		$	418,582							$	359,690

 

The accompanying notes are an integral part of these statements.

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GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

 

		March 31,								December 31,
		2011								2010
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	14,691							$	14,616
Accounts payable to affiliated partnerships			2,708								2,931
Revenue and royalties payable			12,941								12,450
Drilling advances			8,730								4,203
Accrued expenses			1,415								1,331
Derivative financial instruments			13,355								7,433
Total current liabilities			53,840								42,964
Long-term debt			-								87,000
Deferred income taxes			20,415								19,289
Asset retirement obligations			6,705								7,052
Derivative financial instruments			4,335								1,650
Equity:
Common stock, par value $0.01 per share; authorized 100,000,000 shares; issued and outstanding: 25,449,930 in 2011 and
19,726,566 in 2010			254								197
Additional paid-in capital			277,824								148,172
Accumulated other comprehensive income			(7,661	)							(3,000	)
Retained earnings			60,446								54,133
Total GeoResources, Inc. stockholders’ equity			330,863								199,502
Noncontrolling interest			2,424								2,233
Total equity			333,287								201,735
		$	418,582							$	359,690

The accompanying notes are an integral part of these statements.

 

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GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except share and per share amounts)

(unaudited)

 

		Three Months Ended March 31,
		2011								2010
Revenue:
Oil and gas revenues		$	26,614							$	24,729
Partnership management fees			111								159
Property operating income			438								391
Gain on sale of property and equipment			736								145
Partnership income			410								854
Interest and other			330								298
Total revenue			28,639								26,576
Expenses:
Lease operating expense			5,019								5,024
Severance taxes			1,621								1,783
Re-engineering and workovers			394								253
Exploration expense			232								464
General and administrative expense			2,600								1,819
Depreciation, depletion and amortization			5,580								6,351
Hedge ineffectiveness			2,202								(255	)
Loss on derivative contracts			-								13
Interest			586								1,273
Total expense			18,234								16,725
Income before income taxes			10,405								9,851
Income tax expense (benefit):
Current			157								953
Deferred			3,935								2,824
			4,092								3,777
Net income		$	6,313							$	6,074
Less: Net income attributable to noncontrolling interest			-								-
Net income attributable to GeoResources, Inc.		$	6,313							$	6,074
Net income per share (basic)		$	0.26							$	0.31
Net income per share (diluted)		$	0.26							$	0.30
Weighted average shares outstanding:
Basic			24,088,159								19,710,362
Diluted			24,678,013								20,004,083

The accompanying notes are an integral part of these statements

 

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GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY and COMPREHENSIVE INCOME

Three Months Ended March 31, 2011

(In thousands, except share data)

(unaudited)

 

		Common Stock								Additional Paid-in Capital				Retained Earning				Accumulated Other Comprehensive Income (Loss)				Non- Controlling Interest				Total
		Shares				Par value
Balance, December 31, 2010			19,726,566			$	197			$	148,172			$	54,133			$	(3,000	)		$	2,233			$	201,735
Issuance of common stock
For cash, net of issuance costs of $6,469			5,175,000				52				122,434																122,486
Exercise of employee stock options			548,364				5				4,880																4,885
Excess tax benefit from share-based compensation											2,050																2,050
Comprehensive income:
Net income															6,313												6,313
Change in fair market value of hedged positions, net of taxes of $3,086																			(5,122	)							(5,122	)
Net realized hedging losses charged to income, net of taxes of $277																			461								461
Total comprehensive income																											1,652
Equity based compensation expense											288																288
Capital contribution by noncontrolling interest																							191				191
Balance, March 31, 2011			25,449,930			$	254			$	277,824			$	60,446			$	(7,661	)		$	2,424			$	333,287

The accompanying notes are an integral part of this statement.

 

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GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(unaudited)

 

		Three Months Ended March 31,
Cash flows from operating activities:		2011				2010
Net income		$	6,313			$	6,074
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			5,580				6,351
Gain on sale of property and equipment			(736	)			(145	)
Accretion of asset retirement obligations			111				98
Unrealized gain on derivative contracts			-				(87	)
Hedge ineffectiveness (gain) loss			2,202				(255	)
Partnership income			(410	)			(854	)
Partnership distributions			463				1,375
Deferred income taxes			3,935				2,824
Non-cash compensation			288				219
Excess tax benefit from share-based compensation			(2,050	)			-
Changes in assets and liabilities:
Decrease (increase) in accounts receivable			(4,925	)			9,020
Decrease (increase) in prepaid expense and other			(640	)			587
Increase (decrease) in accounts payable and accrued expense			4,135				(7,750	)
Net cash provided by operating activities			14,266				17,457
Cash flows from investing activities:
Proceeds from sale of property and equipment			345				503
Additions to property and equipment			(24,251	)			(12,674	)
Net cash used in investing activities			(23,906	)			(12,171	)
Cash flows from financing activities:
Proceeds from stock options exercised			4,885				64
Excess tax benefit from share-based compensation			2,050				-
Issuance of common stock			122,486				-
Reduction of long-term debt			(87,000	)			-
Net cash provided by financing activities			42,421				64
Net increase in cash and cash equivalents			32,781				5,350
Cash and cash equivalents at beginning of period			9,370				12,660
Cash and cash equivalents at end of period		$	42,151			$	18,010
Supplementary information:
Interest paid		$	302			$	997
Income taxes paid		$	285			$	115

The accompanying notes are an integral part of these statements.

 

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GEORESOURCES, INC. and SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE A: Organization and Basis of Presentation

Description of Operations

GeoResources, Inc. operates a single business segment involved in the acquisition, development and production of, and exploration for, crude oil, natural gas and related products primarily in Texas, North Dakota, Louisiana, Oklahoma, Montana and Colorado.

Consolidated Financial Statements

The unaudited consolidated financial statements include the accounts of GeoResources, Inc. (“GeoResources” or the “Company”) and its majority-owned subsidiaries. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting. All intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. GeoResources’ 2010 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. Except as disclosed herein, there has been no material changes to the information disclosed in the notes to the consolidated financial statements included in GeoResources’ 2010 Annual Report on Form 10-K. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Earnings Per Share

Basic net income per common share is computed based on the weighted average shares of common stock outstanding. Net income per share computations to reconcile basic and diluted net income for the three months ended March 31, 2011 and 2010 consist of the following (in thousands, except per share data):

 

		Three Months Ended March 31,
		2011				2010
Numerator:
Net income available for common shares		$	6,313			$	6,074
Denominator:
Basic weighted average shares			24,088				19,710
Effect of dilutive securities - options			590				294
Diluted weighted average shares			24,678				20,004
Earnings per share
Basic		$	0.26			$	0.31
Diluted		$	0.26			$	0.30

For the period ended March 31, 2011, no options were excluded from the dilutive earnings per share calculation because the average market price of the common stock during the period exceeded all of the options’ exercise prices. For the period ended March 31, 2010, options to purchase 50,000 shares of common stock, were excluded from the dilutive earnings per share calculation because the options’ exercise prices exceeded the average market price of the common stock during the period.

 

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NOTE B: Acquisitions and Dispositions

In November 2010, the Company purchased an 86.67% membership interest in Trigon Energy Partners LLC (“Trigon”) in order to acquire and develop leases in the Eagle Ford shale trend of Texas. The acquisition cost was approximately $11.8 million. The Company fully consolidates Trigon and recorded a noncontrolling interest of $2.4 million at March 31, 2011. During the quarter ended, March 31, 2011, Trigon did not generate any revenue or net income.

In September 2010, the Company entered into an agreement with an unaffiliated third party to jointly acquire and develop mineral leases in the Eagle Ford shale trend of Texas. As part of this agreement, the Company sold a 50% working interest in approximately 20,000 acres for $20 million. For accounting purposes, the Company uses the cost recovery method; under this method proceeds from joint owners are recorded in the balance sheet as a reduction of the carrying value of unproved properties. The purchaser also agreed to pay the drilling costs for the first six wells to be drilled in a contractually specified area of mutual interest (“AMI”). The agreement also provides for an additional $20 million ($10 million net) for additional leasing within the AMI. Subsequent to the initial closing, the Company and the joint owners have continued to acquire leases within the AMI pursuant to the terms of the agreements.

On July 30, 2010, the Company closed an acquisition of producing oil and gas properties located in the Giddings field of central Texas. The purchase price was $16.6 million plus closing adjustments for normal operating activity. The acquisition holds approximately 9,700 net acres and was funded through borrowings under the Company’s credit facility.

In October 2009, the Company initiated a leasing program in Williams County, North Dakota with the objective of establishing a significant operated position in the Bakken trend. In February 2010, the Company entered into agreements with two unaffiliated third parties to jointly develop the project. Cash proceeds to us totaled approximately $20 million and we retained a 47.5% working interest in the project area. The agreements also provided for up to $10 million ($4.75 million net) of additional joint leasing in a contractually specified AMI. For accounting purposes the Company uses the cost recovery method; under this method proceeds from joint owners have been recorded in the balance sheet as a reduction to the carrying value of the unproved properties.

Note C: Recently Issued Accounting Pronouncements

Each reporting period we consider all newly issued but not yet adopted accounting and reporting guidance applicable to our operations and the preparation of our consolidated financial statements. We do not believe that any issued accounting and reporting guidance we have not yet adopted will have a material impact on our consolidated financial statements.

NOTE D: Long-term Debt

The Company has a $250 million credit facility with a borrowing base at March 31, 2011 of $145 million. The credit facility provides for annual interest rates at (a) LIBOR plus 2.25% to 3.00% or (b) the prime rate plus 1.25% to 2.00%, depending upon the amount borrowed. The credit facility also requires the payment of commitment fees to the lender on the unutilized commitment. The commitment rate is 0.50% per annum. The Company is also required to pay customary letter of credit fees. All of the obligations under the credit facility, and guarantees of those obligations, are secured by substantially all of the Company’s assets.

The credit facility requires the maintenance of certain financial ratios, contains customary affirmative covenants, and provides for customary events of default. The Company was in compliance with all covenants at March 31, 2011.

The Company has no principal outstanding under the Company’s credit facility at March 31, 2011. In the first quarter of 2011, we used net proceeds from the public offering of our common stock discussed in Note I, to reduce our outstanding indebtedness under the credit facility. The principal outstanding under

 

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the Company’s credit agreement was $87 million at December 31, 2010. The remaining borrowing base capacity under the credit facility at March 31, 2011, was $145 million. The maturity date for amounts outstanding under the credit facility is October 16, 2012.

Interest expenses for the three months ended March 31, 2011 and 2010 includes amortization of deferred financing costs of $264,000, respectively.

In connection with the initial borrowing from the bank under the credit facility the Company entered into an interest rate swap for the purpose of protecting the Company from undue exposure to interest rate increases. In October 2007, the Company entered into an interest rate swap agreement, providing a fixed rate of 4.79% on a notional $50 million through October 16, 2010. During 2008, the Company broke the swap up into two pieces, a $40 million swap and a $10 million swap each with a fixed rate of 4.29%. The $40 million swap was accounted for as a cash flow hedge while the $10 million swap was marked-to-market with gains and losses included in the Company’s Consolidated Statement of Income. These swaps expired in October 2010.

For the quarter ended March 31, 2010, the Company recognized realized cash settlement losses of $402,000, related to this swap.

NOTE E: Stock Options, Performance Awards and Stock Warrants

In March 2007, the shareholders of the Company approved the GeoResources, Inc. Amended and Restated 2004 Employees’ Stock Incentive Plan (the “Plan”), which authorizes the issuance of options, restricted stock, restricted stock units, and other stock-based incentives to officers, employees, directors and consultants of the Company to acquire up to 2,000,000 shares of the Company’s common stock at prices which may not be less than the stock’s fair market value on the date of grant. The options can be designated as either incentive options or nonqualified options.

A summary of the Company’s stock option activity for the three months ended March 31, 2011 is as follows:

 

		Number of Shares				Weighted Average Exercise Price				Weighted Average Fair Value				Weighted Average Remaining Contractual Life (year)				Aggregate Intrinsic Value
Outstanding, December 31, 2010			1,494,350			$	9.70			$	3.49				7.34			$	18,701,164
Granted			-
Exercised			(556,864	)		$	9.22			$	2.87
Forfeited			-
Outstanding, March 31, 2011			937,486			$	9.98			$	3.86				7.19			$	19,955,977
Vested and exercisable			342,486			$	9.00			$	3.27				6.82			$	7,626,639
Vested and expected to vest			930,880			$	9.98			$	3.85				7.19			$	19,821,818

During the three months ended March 31, 2011, 156,250 options vested with a weighted average exercise price of $9.25. The weighted average grant date fair value of these options was $4.35 per option. At March 31, 2011, there were 595,000 unvested options with a weighted average remaining amortization period of 2.04 years.

The Company recognized compensation expense based upon the fair value of the options at the date of grant determined by the Black-Scholes option pricing model. For the quarters ended March 31, 2011 and 2010 the Company recognized compensation expense of $288,000 and $219,000, respectively,

 

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related to these options. As of March 31, 2011, the future pre-tax expense of non-vested stock options is $1.8 million to be recognized through the second quarter of 2014.

The Company has warrants to purchase 613,336 shares of common stock outstanding at March 31, 2011. The warrants have an exercise price of $32.43 and have a remaining life of 2 years and 2 months.

NOTE F: Income Taxes

Deferred income taxes are recognized for the tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and tax purposes, as required by current accounting standards. The deferred tax is measured using the enacted tax rates applicable to periods when these differences are expected to reverse.

Uncertain Tax Positions

The Company will consider a tax position settled if the taxing authority has completed its examinations, the Company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future. The Company uses the benefit recognition model which contains a two-step approach, a more-likely-than-not recognition criteria and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. The amount of interest expense recognized by the Company related to uncertain tax positions is computed by applying the applicable statutory rate of interest to the difference between the tax position recognized and the amount previously taken or expected to be taken in a tax return.

At March 31, 2011, the Company did not have any uncertain tax positions that would require recognition. The Company’s uncertain tax positions could change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position.

The Company files a consolidated federal income tax return and various combined and separate filings in several state and local jurisdictions.

It is also the Company’s practice to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statements of Income. As of March 31, 2011, the Company did not have any accrued interest or penalties associated with any unrecognized tax liabilities. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statutes of limitations prior to March 31, 2012.

NOTE G: Derivative Financial Instruments

The Company enters into various crude oil and natural gas hedging contracts, primarily costless collars and swaps, in an effort to manage its exposure to product price volatility. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has designated its commodity derivative contracts as cash flow hedges designed to achieve more predictable cash flows, as well as to reduce its exposure to price volatility. While the use of derivative instruments limits the downside risk of adverse price movements, they also limit future revenues from favorable price movements.

At March 31, 2011, accumulated other comprehensive income (loss) consisted of unrecognized losses of $7.7 million, net of taxes of $4.6 million, representing the inception to date change in mark-to-market value of the effective portion of the Company’s open commodity contracts, designated as cash flow

 

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hedges, as of the balance sheet date. At December 31, 2010, accumulated other comprehensive income (loss) consisted of unrecognized losses of $3.0 million, net of taxes of $1.8 million. For the quarter ended March 31, 2011, the Company recognized net realized cash settlement losses on commodity derivatives of $738,000. For the quarter ended March 31, 2010, the Company recognized realized cash settlement gains of $104,000. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at March 31, 2011, the Company expects to reclassify net losses of $9.9 million into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

During the first quarter of 2011 the Company entered into one additional natural gas swap contract, three crude oil collars, and two crude oil swaps. The natural gas swap has a term of January 2012 to March 2013 and provides for 75,000 MMBTUs per month. The swap has a fixed price of $4.85 per MMBTU. The first crude oil collar has a term of February 2011 through December 2011 and provides 5,000 Bbls per month. The floor price is $85.00 per Bbl and the ceiling price is $106.08 per Bbl. The second crude oil collar has a term of January 2012 through December 2012 and provides 10,000 Bbls per month. The floor price is $85.00 per Bbl and the ceiling price is $110.00 per Bbl. The third crude oil collar has a term of March 2011 through December 2011 and provides for 5,000 Bbls per month. The floor price is $100.00 per Bbl and the ceiling price is $114.00 per Bbl. The first crude oil swap has a term of January 2012 through December 2012 and provides for 10,000 Bbls per month. The swap has a fixed price of $103.95 per Bbl. The second crude oil swap has a term of January 2013 through December 2013 and provides for 10,000 Bbls per month. The swap has a fixed price of $101.85 per Bbl.

Subsequent to March 31, 2011, the Company entered into one additional crude oil swap. The crude oil swap has a term of May 2011 through December 2011 and provides for 6,250 Bbls per month. The swap has a fixed price of $110.00 per Bbl.

At March 31, 2011, the Company had hedged its exposure to the variability in future cash flows from forecasted oil and gas production volumes as follows:

 

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		Total Remaining Volume				Floor     Price				Ceiling /     Swap Price
Crude Oil Contracts (Bbls):
Swap contracts:
2011			211,500							$	74.37
2011			63,000							$	88.45
2011			90,000							$	85.05
2011			45,000							$	85.16
2012			120,000							$	86.85
2012			120,000							$	87.22
2012			120,000							$	103.95
2013			120,000							$	101.85
Costless collars contracts:
2011			45,000			$	85.00			$	106.08
2011			45,000			$	100.00			$	114.00
2012			120,000			$	85.00			$	110.00
Natural Gas Contracts (Mmbtu)
Swap contracts
2011			630,000							$	6.450
2012			150,000							$	6.450
2012			450,000							$	6.415
2012			900,000							$	4.850
2013			225,000							$	4.850
Costless collars contracts:
2011			809,253			$	7.000			$	9.200

All derivative instruments are recorded on the consolidated balance sheet at fair value. The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheets (in thousands):

 

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Derivatives designated as ASC 815 hedges:		Asset Derivatives										Liability Derivatives
				Fair Value										Fair Value
		Balance Sheet Location		Mar. 31, 2011				Dec. 31, 2010				Balance Sheet Location		Mar. 31,   2011				Dec. 31,   2010
Commodity contracts		Current derivative financial instruments asset		$	3,420			$	4,282			Current derivative financial instruments liability		$	(13,355	)		$	(7,433	)
Commodity contracts		Long-term derivative financial instruments asset			647				851			Long-term derivative financial instruments liability			(4,335	)			(1,650	)
				$	4,067			$	5,133					$	(17,690	)		$	(9,083	)

 

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Commodity derivative contracts – The following table summarizes the effects of commodity derivative instruments on the consolidated statements of income for the three months ended March 31, 2011 and 2010 (in thousands):

 

Derivatives designated as ASC 815 hedges:		Amount of Gain or (Loss) Recognized in OCI on Derivative  (Effective Portion)								Location of Gain or (Loss) Reclassified from OCI intoIncome (Effective Portion)		Amount of Gain or (Loss) Reclassified from OCI into Income  (Effective Portion)
		Mar. 31, 2011				Mar. 31, 2010						Mar. 31, 2011				Mar. 31, 2010
Commodity										Oil and gas
contracts		$	(8,208	)		$	6,468			revenues		$	(738	)		$	104
Interest rate
swap contract			-				(53	)		Interest expense			-				(402	)
		$	(8,208	)		$	6,415					$	(738	)		$	(298	)

 

				Amount of Gain or (Loss) Recognized in Income  on Derivative (Ineffective Portion)
		Location of (Gain) or Loss
Derivatives in ASC 815 Cash Flow Hedging Relationships:		Recognized in Income on Derivative (Ineffective Portion)		Mar. 31, 2011				Mar. 31, 2010
Commodity contracts		Hedge ineffectiveness		$	(2,202	)		$	255
				Amount of Gain or (Loss) Recognized in Income on Derivative
Derivatives not designated as ASC 815 hedges:		Location of (Gain) or Loss Recognized in Income on Derivative		Mar. 31, 2011				Mar. 31, 2010
Realized cash settlements on interest rate swap		Loss on derivative contracts		$	-			$	(100	)
Unrealized (gains) on commodity contracts		Loss on derivative contracts			-				87
				$	-			$	(13	)

Contingent features in derivative instruments – None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s derivative contracts are high credit quality financial institutions.

NOTE H: Fair Value Disclosures

ASC Topic 820 defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.

 

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ASC Topic 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

 

•

Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

 

•

Level 2 – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

 

•

Level 3 – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of the input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

Cash, Cash Equivalents, Accounts Receivable and Payable and Royalties Payable – The carrying amount of cash and cash equivalents, accounts receivable and payable and royalties payable are estimated to approximate their fair values due to the short maturities of these instruments.

Long-term Debt – The Company’s long-term debt obligation bears interest at floating market rates, so carrying amounts and fair values are approximately equal.

Derivative Financial Instruments – Derivative financial instruments are carried at fair value. Commodity derivative instruments consist of costless collars and swaps for crude oil and natural gas. The Company’s costless collars are valued based on the counterparty’s marked-to-market statements, which are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is the NYMEX futures index. The Company’s model is validated by the counterparty’s marked-to-market statements. The swaps are also designated as Level 2 within the valuation hierarchy. The discount rate used in determining the fair values of these instruments includes a measure of nonperformance risk. The Company’s interest rate swaps are valued using the counterparty’s marked-to-market statement, which can be validated using modeling techniques that include market inputs such as publically available interest rate yield curves, and is designated as Level 2 within the valuation hierarchy.

The table below presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2011 and December 31, 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

 

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Fair Value of Financial Assets and Liabilities - March 31, 2011

(in thousands)

		Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Balances as of March 31, 2011
Current portion of derivative financial instrument asset (1)			-			$	3,420				-			$	3,420
Long-term portion of derivative financial instrument asset (1)			-				647				-				647
Current portion of derivative financial instrument liability (1)			-				(13,355	)			-				(13,355	)
Long-term portion of derivative financial instrument liability (1)			-				(4,335	)			-				(4,335	)

 

(1)

Commodity derivative instruments accounted for as cash flow hedges.

Fair Value of Financial Assets and Liabilities - December 31, 2010

(in thousands)

 

		Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Balances as of December 31, 2010
Current portion of derivative financial instrument asset (1)			-			$	4,282				-			$	4,282
Long-term portion of derivative financial instrument asset (1)			-				851				-				851
Current portion of derivative financial instrument liability (1)			-				(7,433	)			-				(7,433	)
Long-term portion of derivative financial instrument liability (1)			-				(1,650	)			-				(1,650	)

 

(1)

Commodity derivative instruments accounted for as cash flow hedges.

At March 31, 2011, and December 31, 2010, the Company did not have any assets or liabilities measured at fair value on a recurring basis that meet the definition of Level 1 or Level 3.

Asset Impairments – The Company reviews proved oil and gas properties for impairment quarterly and when events and circumstances indicate a significant decline in the recoverability of the carrying value of such properties. When events and circumstances indicate a significant decline in the

 

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recoverability of a property, the Company estimates the future cash flows expected in connection with the property and compares such future cash flows to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include significant Level 3 assumptions associated with estimates of future oil and gas production, commodity prices based on commodity futures price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The Company did not record any asset impairments during the three month periods ended March 31, 2011 or 2010.

Asset Retirement Obligations – The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the Company’s asset retirement obligation is presented in Note J.

Property Acquisitions and Business Combinations – The Company records the identifiable assets acquired, liabilities assumed and any non-controlling interests at fair value at the date of acquisition. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on commodity futures price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate of future natural gas and crude oil prices, operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note B.

NOTE I: Public Offering of Common Stock

On January 19, 2011, the Company closed a public offering of 5,175,000 shares of common stock issued by the Company (including 675,000 shares of over allotment granted to underwriters) and 989,000 shares sold by certain selling shareholders in a public offering, at a price of $25.00 per share. The Company’s net proceeds from the offering were approximately $122.5 million after deducting the underwriters’ discount and other offering expenses.

NOTE J: Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration, in accordance with applicable local, state and federal laws. The Company determines its obligation by calculating the present value of estimated cash flows related to plugging and abandonment obligations. The changes to the Asset Retirement Obligations (“ARO”) for oil and gas properties and related equipment during the three months ended March 31, 2011, are as follows (in thousands):

 

Asset retirement obligation, January 1, 2011		$	7,052
Accretion expense			111
Obligations on sold properties			(464	)
Additional liabilities incurred			6
Asset retirment obligation, March 31, 2011		$	6,705

 

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NOTE K: Related Party Transactions

Accounts receivable at March 31, 2011, and December 31, 2010, includes $864,000 and $753,000, respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at March 31, 2011 and December 31, 2010, also includes $207,000 and $219,000, respectively, due from OKLA Energy Partners LP (“OKLA Energy”). Both of these partnerships are oil and gas limited partnerships for which a subsidiary of the Company serves as general partner. These amounts represent the limited partnerships’ share of property operating expenditures incurred by operating subsidiaries of the Company on their behalf, as well as accrued management fees. Accounts payable at March 31, 2011 and December 31, 2010, includes $2.1 million and $2.3 million, respectively, due to SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at March 31, 2011 and December 31, 2010, also includes $626,000 and $654,000, respectively, due to OKLA Energy for oil and gas revenues collected on its behalf.

Subsidiaries of the Company operate the majority of the oil and gas properties in which the two limited partnerships have an interest. Under this arrangement, the Company collects revenues from purchasers and incurs property operating and development expenditures on behalf of the partnerships. These revenues are paid monthly to each partnership, which in turn reimburse the Company for the partnership’s share of expenditures. The Company earned partnership management fees during the three months ended March 31, 2011 and 2010 of $111,000 and $159,000, respectively.

NOTE L: Equity Investments

The Company holds investments, in the form of general partnership interests, in two affiliated partnerships, SBE Partners and OKLA Energy. The Company accounts for these investments using the equity method of accounting. Under this accounting method the Company records its net share of income and expenses in the Partnership Income line item of its Consolidated Statement of Income. Contributions to the investment increase the Company’s investment while distributions from the partnership decrease the Company’s carrying value of the investment.

OKLA Energy, formed during 2008, holds direct working interests in producing oil and gas properties located throughout Oklahoma. The Company’s 2% general partner interest reverts to 35.66% when the limited partner realizes a contractually specified rate of return. The Company recorded losses in partnership income related to this investment for the three months ended March 31, 2011 and 2010 of $1,000 and $2,000, respectively.

SBE Partners, formed during 2007, holds direct working interests in producing oil and gas properties located in Giddings field in Texas. Previously, the Company held a 2% general partner interest which increased after reaching a cumulative payout. As result of the sale of certain properties and subsequent distribution of proceeds by the Partnership cumulative payout was achieved and the Company’s general partner interest increased to 30%. The Company recorded partnership income related to this investment for each of the three months ended March 31, 2011 and 2010 of $411,000 and $856,000, respectively.

The Company’s carrying value for its equity investment in OKLA Energy at March 31, 2011 and December 31, 2010, was $695,000 and $709,000, respectively. The Company’s carrying value for its equity investment in SBE Partners at March 31, 2011 and December 31, 2010 was $1.5 million and $1.6 million, respectively.

The following is a summary of selected financial information of SBE Partners, LP for the three months ended March 31, 2011 and 2010 (in thousands):

 

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		Three Months Ended March 31,
		2011				2010
		(in thousands)
Summary of Partnership Operations:
Revenues		$	3,900			$	5,943
Income from continuing operations		$	1,606			$	2,583
Net income		$	1,606			$	2,583

 

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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 significant factors that have affected certain aspects of our financial position and operating results during the periods included in the accompanying unaudited consolidated financial statements. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes thereto, included elsewhere in this Quarterly Report on Form 10-Q and should further be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2010.

Forward-Looking Information

Certain statements contained in this report on Form 10-Q are not statements of historical fact and constitute forward-looking statements within the meaning of the various provisions of the Securities Act of 1933, as amended, (the “Securities Act”) and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including, without limitation, the statements specifically identified as forward-looking statements within this report. Many of these statements contain risk factors as well. In addition, certain statements in our future filings with the SEC, in press releases and in oral and written statements made by or with our approval which are not statements of historical fact constitute forward-looking statements within the meaning of the Securities Act and the Exchange Act. Examples of forward-looking statements, include, but are not limited to: (i) projections of capital expenditures, revenues, income or loss, earnings or loss per share, capital structure, and other financial items, (ii) statements of our plans and objectives or our management or board of directors including those relating to planned development of our oil and gas properties, (iii) statements of future economic performance and (iv) statements of assumptions underlying such statements. Words such as “believes,” “anticipates,” “expects,” “intends,” “targeted,” “may,” “will” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

 

•

changes in production volumes, worldwide demand and commodity prices for oil and natural gas;

 

•

changes in estimates of proved reserves;

 

•

declines in the values of our oil and natural gas properties resulting in impairments;

 

•

the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves;

 

•

our ability to acquire leases, drilling rigs, supplies and services on a timely basis and at reasonable prices;

 

•

reductions in the borrowing base under our credit facility;

 

•

risks incident to the drilling and operation of oil and natural gas wells;

 

•

future production and development costs;

 

•

the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on prices;

 

•

the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America;

 

•

changes in environmental laws and the regulation and enforcement related to those laws;

 

•

the identification of and severity of environmental events and governmental responses to the events;

 

•

legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, derivatives reform, and changes in state, federal and foreign income taxes;

 

•

the effect of oil and natural gas derivatives activities;

 

•

conditions in the capital markets; and

 

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•

other risks, described in Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2010, as may be supplemented and updated from time to time in our other SEC filings.

Such forward-looking statements speak only as of the date on which such statements are made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made to reflect the occurrence of unanticipated events.

General Overview

We are an independent oil and gas company engaged in the acquisition, development and production of oil and gas reserves in multiple basins. As further discussed in this report, future growth in assets, earnings, cash flows and share values will be dependent upon our ability to acquire, discover and develop commercial quantities of oil and gas reserves that can be produced at a profit, and assemble an oil and gas reserve base with a market value exceeding its acquisition, development and production costs.

Our strategy includes a combination of acquisition, development and exploration activities. Historically, we have shifted our emphasis among these basic activities to take advantage of changing market conditions and to facilitate profitable growth. The majority of our efforts are currently focused on developing our oil-weighted acreage positions in the Bakken trend of North Dakota and Montana and the Eagle Ford trend of Texas. In addition, it is essential that, over time, our personnel expand our current projects and/or generate additional projects so we have the potential of economically replacing our production and increasing our proved reserves. Following is a brief outline of our current plans:

• Accelerate the development of our acreage positions in the Bakken and Eagle Ford trends;

• Expand our acreage positions and drilling inventory;

• Solicit industry partners, on a promoted basis, where we can retain operations and control large acreage positions in order to diversify, enhance economics and generate operating fees;

• Generate additional exploration and development projects;

• Acquire oil and gas properties with producing reserves and development and exploration potential, within our focus areas;

• Selectively divest assets to high-grade our producing property portfolio and to lower corporate wide “per-unit” operating and administrative costs, and focus attention on existing fields and new projects with greater development and exploitation potential; and

• Obtain additional capital, as needed, through the issuance of equity securities and/or through debt financing.

While the impact and success of our plans cannot be predicted with accuracy, management’s goal is to replace production and further increase our reserve base at an acquisition or finding cost that will yield attractive rates of return and increase shareholder value.

In addition to our fundamental business strategy, we intend to pursue corporate acquisitions and mergers. We believe that a corporate acquisition or merger could potentially accelerate growth, increase market visibility and realize operating and administrative benefits. Accordingly, we intend to consider any such opportunities which may become available that we consider beneficial to our shareholders. The primary financial considerations in the evaluation of any such potential transactions include, but are not limited to: (1) the potential to increase assets in a core area, (2) the opportunity to increase our earnings and cash flow on a per share basis, (3) development and exploration potential, and (4) realization of administrative savings. Further, we believe a corporate acquisition could lead to increased visibility in the

 

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market place, greater trading volume and therefore greater shareholder liquidity and possibly access to capital with lower costs.

Oil and Gas Properties

We use the Successful Efforts method of accounting for oil and gas operations. Under this method, costs to acquire oil and gas properties, drill successful exploratory wells, drill and equip development wells and install production facilities are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs are charged to operations as incurred. Depreciation, depletion and amortization (“DD&A”) of the capitalized costs associated with proved oil and gas properties are computed using the unit-of-production method, at the field level, based on proved reserves. Oil and gas properties are periodically assessed for impairment and generally written down to estimated fair value if the sum of estimated future undiscounted pretax cash flows, based on engineering and expected economic circumstances, is less than the carrying value of the asset. The fair value of impaired assets is generally determined using market values, if known, or using reasonable projections of production, prices and costs and discount rates commensurate with the risks involved.

Recent Property Acquisitions and Divestitures

In November 2010, we purchased an 86.67% membership interest in Trigon Energy Partners LLC (“Trigon”) in order to acquire and develop leases in the Eagle Ford shale trend of Texas. The acquisition cost was approximately $11.8 million. We fully consolidated Trigon and recorded a noncontrolling interest of $2.4 million as of March 31, 2011. During the quarter ended March 31, 2011, Trigon did not generate any revenue or net income.

In September 2010, we entered into an agreement with an unaffiliated third party to jointly acquire and develop mineral leases in the Eagle Ford shale trend of Texas. As part of this agreement, we sold a 50% working interest in approximately 20,000 acres for $20 million. The purchaser also agreed to pay the drilling costs for the first six wells to be drilled in a contractually specified area of mutual interest (“AMI”). The agreement also provides for an additional $20 million ($10 million net) for additional leasing within the AMI. Subsequent to the initial closing, the Company and the joint owners have continued to acquire leases within the AMI pursuant to the terms of the agreements.

On July 30, 2010, we closed an acquisition of producing oil and gas properties located in the Giddings field of central Texas. The purchase price was $16.6 million plus closing adjustments for normal operations activity. The acquisition holds approximately 9,700 net acres and was funded through borrowings under our credit facility.

In October 2009, we initiated a leasing program in Williams County, North Dakota with the objective of establishing a significant operated position in the Bakken trend. In February 2010, we entered into agreements with two unaffiliated third parties to jointly develop the project. Cash proceeds to us totaled approximately $20 million and we retained a 47.5% working interest in the project area. The agreements also provided for up to $10 million ($4.75 million net) of additional joint leasing in a contractually specified AMI.

Results of Operations

Three months ended March 31, 2011, compared to three months ended March 31, 2010.

The Company recorded net income of $6.3 million for the three months ended March 31, 2011 compared to net income of $6.1 million for the same period in 2010. This $239,000 increase resulted primarily from the following factors:

 

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Net amounts contributing to increase (decrease) in net income (in 000s):
Oil and gas sales		$	1,885
Lease operating expenses			5
Severance taxes			162
Exploration expense			232
Re-engineering and workovers			(141)
General and administrative expenses (“G&A”)			(781)
Depletion, depreciation and amortization expense (“DD&A”)			771
Net interest income (expense)			677
Hedge ineffectiveness			(2,457)
Gain (loss) on derivative contracts			13
Gain (loss) on sale of property			591
Other income - net			(403)
Income before income taxes			554
Provision for income taxes			(315)
Net income		$	239

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Net revenues from oil and gas sales increased $1.9 million, or 8%. Sales are a function of oil and gas volumes sold and average sales prices. Commodity prices resulted in a $3.3 million increase in revenue. Increases in oil prices resulted in a $3.7 million increase in revenue which was offset by a $425,000 decrease due to gas prices. The net commodity price increases of $3.3 million were partially offset by a $1.4 million decrease due to less production volume. Our gas production decreased by 21% primarily due to the suspension of drilling gas wells in the Giddings field due to low natural gas prices and normal production declines. Price and production comparisons are set forth in the following table. Our 2011 oil production remained flat and experienced a decline from fourth quarter 2010 primarily as a result of production delays related to severe weather conditions which affected our production operations and support services in North Dakota.

 

		Percent increase      (decrease)		Three Months Ended March 31,
				2011				2010
Oil Production (Mbbls)		0%			250				249
Gas Production (MMcf)		-21%			1,011				1,279
Barrel of Oil Equivalent (MBOE)		-9%			419				462
Average Price Oil Before Hedge Settlements (per Bbl)		25%		$	93.03			$	74.21
Average Realized Price Oil (per Bbl)		21%		$	85.37			$	70.62
Average Price Gas Before Hedge Settlements (per Mcf)		-17%		$	4.03			$	4.83
Average Realized Price Gas (per Mcf)		-7%		$	5.20			$	5.61

Production Taxes. Production taxes decreased by $162,000 or 9%. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for the quarter ended March 31, 2011 and 2010 were 5.9% and 7.2%, respectively, of oil and gas sales before the effects of hedging. The 2011 rate decreased from 2010 due to an increase in oil revenues and a decrease in gas revenues. In the states where we primarily have production, oil revenues are taxed at a lower rate than natural gas revenues.

General and Administrative Expenses. G&A increased $781,000 due primarily to increases in personnel hired in the last 12 months as well as general pay increases. The total non-cash charges related

 

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to stock-based compensation included in G&A expense for the three month periods ended March 31, 2011 and 2010 were $288,000 and $219,000, respectively.

Depreciation, Depletion and Amortization. DD&A expense decreased by $771,000 or 12%, due to higher reserves as of March 31, 2011 verses March 31, 2010 and lower production volumes. On a units-of-production basis, DD&A per BOE decreased from $13.75 to $13.33. DD&A on oil and gas properties is computed on the units-of-production method, with production volumes as the numerator and estimated proved reserve volumes as the denominator.

Interest Income and Expense. Interest expense decreased by $687,000 due to lower debt levels in the first quarter of 2011 compared to the same period in 2010. For the three months ended March 31, 2011, average outstanding debt was $19,000,000 compared to $69,000,000 for the same period in 2010. Interest income decreased by $10,000 in the first quarter of 2011 compared to the same period in 2010.

Hedge Ineffectiveness. During the first quarter of 2011 the loss from hedge ineffectiveness was $2.2 million compared to a gain of $255,000 for the same period in 2010. The ineffectiveness in 2011 relates to our derivatives accounted for as a cash flow hedge, which decreased in value. The change in the ineffective portion of these derivatives was a loss. During the first quarter of 2010, our derivatives accounted for as cash flow hedges increased in value; therefore, the change in the ineffective portion of these derivatives was a gain.

Other Income. Other income decreased by $403,000 primarily due to a decrease in partnership income of $444,000 offset by an increase in property operating income of $47,000 in the first quarter of 2011 compared to the same period in 2010.

Income Tax Expense. Income tax expense for the first quarter of 2011 was $4.1 million compared to $3.8 million for the same period in 2010. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate during the first quarter of 2011 was approximately 39% versus 38% in the same period during 2010.

Impact of Changing Prices and Costs

Our revenues and the carrying value of our oil and gas properties are subject to significant change due to changes in oil and gas prices. The oil and gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and not adjust downward in proportion to prices. Material changes in prices also impact the current revenue stream, estimates of future reserves, depletion expense, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Oil prices decreased appreciably during 2008 but recovered somewhat during the last half of 2009 through the first quarter of 2011. Average realized oil prices of $85.37 per Bbl, net of hedges, for the three months ended March 31, 2011, were 21% higher than for the comparable period in 2010. Average realized natural gas prices of $5.20 per Mcf, net of hedges, for the three months ended March 31, 2011, were 7% lower than for the comparable period in 2010. Should significant price decreases occur or should prices fail to remain at levels which will facilitate reinvestment of cash flow to economically replace current production, we could experience difficulty in developing our assets and growing our production and reserves.

Fluctuating gas prices in 2009 caused us to suspend our drilling activities directed in the Giddings field and then restart them resulting in a decline of 15% in our gas production from the fourth quarter 2009 to the first quarter 2010. We announced in 2010 our suspension of those activities again in the current low    

 

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gas price environment and we anticipate restarting that drilling activity when natural gas prices recover. We expect a similar level of decline in our natural gas production as we experienced in 2011.

Hedging Activities

In an attempt to reduce our sensitivity to oil and gas price volatility and secure favorable debt financing, we have and will likely continue to enter into hedging transactions which may include fixed price swaps, price collars, puts and other derivatives. Management believes our hedging strategy will result in greater predictability of internally generated funds, which can be dedicated to capital development projects and corporate obligations.

We do not engage in speculative commodity trading activities and do not hedge all available or anticipated quantities. Our strategy with regard to hedging includes the following factors:

 

(1)

Secure and maintain favorable debt financing terms;

(2)

Minimize price volatility and generate internal funds available for capital development projects and additional acquisitions;

(3)

“Lock-in” growth in revenues, cash flows and profits for financial reporting purposes; and

(4)

Allow certain quantities to float, particularly in months with high price potential.

We believe that commodity speculation and trading activities are inappropriate for us, but further believe appropriate management of realized prices is an integral part of managing our business strategy.

Administrative and Operating Costs

We continue to focus on cost-containment efforts regarding lower per-unit administrative and operating costs. However, we must continue to attract and retain competent management, technical and administrative personnel in pursuing our business strategy and fulfilling our contractual obligations.

Liquidity and Capital Resources

We expect to finance our future acquisition, development and exploration activities through working capital, cash flow from operating activities, our bank credit facility, sale of non-strategic assets, various means of corporate and project finance and possibly through the issuance of additional debt and equity securities. In addition, we intend to continue to partially finance our drilling activities through the sale of participations to industry partners on a promoted basis, whereby we will earn working interests in reserves and production greater than our proportionate capital cost.

Credit Facility

As of March 31, 2011, our borrowing base under our credit facility with Wells Fargo Bank was $145 million and we did not have any outstanding indebtedness. The borrowing base is subject to redetermination on May 1 and November 1 of each year. We expect that our bank group will reaffirm our borrowing base at $145 million, effective May 1, 2011. As of May 5, 2011 our outstanding balance under the credit facility was zero.

Cash Flows from Operating Activities

For the three months ended March 31, 2011, our net cash provided by operating activities was $14.3 million, versus $17.5 million from the same period in 2010. We believe that we have sufficient liquidity and capital resources to execute our business plans over the next twelve months and foreseeable future. We expect to fund our planned capital program through debt, working capital and the proceeds from our public stock offering.

 

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Cash Flows from Investing Activities

Cash applied to oil and gas capital expenditures for the three months ended March 31, 2011 and 2010, was $24.3 million and $12.7 million, respectively. In addition, cash generated from the sale of oil and gas properties for the three months ended March 31, 2011 and 2010 was $345,000 and $503,000, respectively. Capital expenditures for the three months ended March 31, 2011 were financed with working capital. We expect to spend approximately $263 million in additional capital expenditures during the remainder of 2011 and 2012.

Capital Budget

We continue to expand our portfolio of drilling and development projects and therefore have increased our projected drilling and development expenditures. As summarized below, we estimate our capital budget for 2011 will total $114.0 million. While the table includes the bulk of our currently identified drilling for 2011, we are constantly working on developing and acquiring new opportunities. A benefit of our property portfolio is that it consists of relatively new acreage positions and therefore we generally have two to five years to drill the bulk of our undeveloped leases. In addition, many of our drilling opportunities, including the bulk of our gas drilling locations, are “held by production” or long term leases and therefore not subject to lease expiration or significant future incremental carrying costs. Accordingly, we have a substantial ability to adjust our capital spending as industry circumstances dictate or as opportunities arise.

We have initiated drilling on our operated Bakken acreage in the Williston Basin and our operated Eagle Ford acreage in Texas and our Bakken non-operated holdings continue to be actively developed. Those projects represent the bulk of our planned capital expenditures for 2011, as set forth in the table below. However, we continue evaluating whether to shift our expenditures between geographic areas and projects in an attempt to maximize cash flow and take advantage of regional differences in net commodity prices and service costs or other matters we deem of significance.

While industry circumstances may require us to make capital expenditure adjustments, our capital budget reflects our current intent to accelerate our Bakken and Eagle Ford drilling and further expand our acreage. To a lesser extent, we intend to drill certain locations in the Austin Chalk and certain of our prospects on the Gulf Coast, but those projects could be deferred in favor of increased activity in these other areas or so long as low natural gas prices prevail.

The projects, estimated costs and timing of actual expenditures are subject to significant change as we continue to technically and economically evaluate existing and alternative projects, as we further expand our portfolio, and as industry conditions dictate. Estimated expenditures are also subject to significant change. There can be no assurance that all of the projects identified and summarized in the table below will remain competitive or viable and therefore certain projects may be sold or abandoned by us to redeploy capital. However, in the opinion of management, at present, we have sufficient cash flows and liquidity to fulfill lease obligations or otherwise maintain all material mineral leases. Our current estimate of our capital expenditure spending for 2011 is as follows:

 

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		($ in Millions)				Percent of     Capital Budget
Bakken - operated (1)		$	29.5				26%
Bakken - non-operated (2)			21.0				18%
Eagle Ford (3)			15.8				14%
Giddings Field (4)			8.3				7%
Louisiana (5)			7.8				7%
Acreage and seismic (6)			25.0				22%
Other drilling operations			6.6				6%
Total		$	114.0				100%

Notes:

(1)

Includes approximately $26.0 million allocated to our operated Bakken drilling project in Williams County, North Dakota. The remaining $3.5 million represents planned drilling on Bakken spacing units we control in eastern Montana. In Williams County, North Dakota, we completed drilling and completion of our initial three wells in the first quarter of 2011. After drilling two wells in eastern Montana, we have moved the rig back to Williams County to continue our development program. We have contracted a second drilling rig which should begin drilling in Williams County early in the 3rd quarter of 2011.

(2)

Represents continuation of our non-operated program. Approximately $17.5 million represents activities in Mountrail County, North Dakota and $3.5 million represents planned drilling in eastern Montana.

(3)

Represents our net estimated cost of drilling 13 planned wells with Ramshorn where we have a 50% carried interest in six wells at no cost to us.

(4)

Represents our net estimated cost of drilling three wells in the Giddings Field, Texas.

(5)

Represents our net estimated cost of drilling seven wells in the St. Martinville Field and one well at Quarantine Bay, Louisiana.

(6)

Includes approximately $22.0 million allocated to additional acreage and $3.0 million allocated to seismic activities. We intend to continue expanding our acreage positions in our focus areas and therefore, with success, our capital spending could exceed the amounts shown above.

Pending success, continuing favorable industry and economic conditions and availability of equipment and services among other factors, our current estimate of capital expenditures for 2012 is approximately $173.0 million, largely directed toward continued Bakken and expanded Eagle Ford drilling and incremental acreage acquisitions.

 

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Item 3.    Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from changes in commodity prices. In the normal course of business, we enter into derivative transactions, including commodity price collars, swaps and floors to mitigate our exposure to commodity price movements. We do not participate in these transactions for trading or speculative purposes. While the use of these arrangements may limit the benefit to us of increases in the prices of oil and natural gas, it also limits the downside risk of adverse price movements.

The following is a list of contracts outstanding at March 31, 2011:

 

Transaction Date		Transaction Type				Beginning				Ending				Price Per Unit				Remaining Annual Volumes				Fair Value Outstanding as of March 31, 2011
																						(in thousands)
Natural Gas
October-07			Collar				01/01/11				12/31/11				$7.00 - $9.20				809,253			$	1,968
December-09			Swap				04/01/11				03/31/12				$6.450				780,000				1,452
December-09			Swap				04/01/12				12/31/12				$6.415				450,000				647
January-11			Swap				01/31/11				12/31/13				4.850				1,125,000				(208)
																							3,859
Crude Oil
October-07			Swap				01/01/11				12/31/11				$74.37				211,500				(7,074)
January-10			Swap				01/01/11				12/31/11				$88.45				63,000				(1,227)
August-10			Swap				09/01/10				12/31/11				$85.05				90,000				(2,031)
August-10			Swap				01/01/12				12/31/12				$86.85				120,000				(2,326)
October-10			Swap				01/01/11				12/31/11				$85.16				45,000				(1,008)
October-10			Swap				01/01/12				12/31/12				$87.22				120,000				(2,276)
January-11			Collar				02/01/11				12/31/11				$85.00 - $106.08				45,000				(449)
January-11			Collar				01/01/12				12/31/12				$85.00 - $110.00				120,000				(589)
March-11			Collar				03/01/11				12/31/11				$100.00 - $114.00				45,000				(47)
March-11			Swap				01/01/12				12/31/12				$103.95				120,000				(279)
March-11			Swap				01/01/13				12/31/13				$101.85				120,000				(176)
																							(17,482)
																						$	(13,623)

 

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Item 4.    Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our Chief Executive Officer, Chief Financial Officer and other members of management evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of March 31, 2011. Based upon their evaluation of these disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of March 31, 2011, in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive and principal financial officers to allow timely discussion regarding required disclosure.

Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting that occurred during the quarter ended March 31, 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

We are not a party to, nor are any of our properties subject to, any material pending legal proceedings. We know of no material legal proceedings contemplated or threatened against the Company.

 

Item 1A.

Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A- Risk Factors” in our Annual Report for the year ended December 31, 2010 on Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2010 Annual Report on Form 10-K may not be the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.

 

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds		None
Item 3.  Defaults Upon Senior Securities		None
Item 4.  Reserved
Item 5.  Other Information		None

 

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Item 6.    Exhibits

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended March 31, 2011.

 

10.51		Form of Restricted Stock Unit Agreement (1)
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)
31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)
32.1		Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)
32.2		Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)

 

(1)	Filed herewith.

 

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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.

 

May 6, 2011

 

Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

 

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