U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

o		Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission file number: 001-32624

FieldPoint Petroleum Corporation

(Exact name of small business issuer as specified in its charter)

Colorado		84-0811034
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

1703 Edelweiss Drive
Cedar Park, Texas 78613

(512) 250-8692

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the 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 þ No o

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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

Large accelerated filer o		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company þ

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

As of August 12, 2011, the number of shares outstanding of the Registrant’s $.01 par value common stock was 7,997,175.

 

 

PART I

Item 1.		Condensed Consolidated Financial Statements

FieldPoint Petroleum Corporation

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

		June 30,				December 31,
		2011				2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	2,246,409			$	984,770
Certificates of deposit			44,446				44,422
Accounts receivable:
Oil and natural gas sales			765,226				723,218
Joint interest billings, less allowance for doubtful accounts of $99,192, each period			206,745				246,655
Prepaid income taxes			276,000				206,000
Deferred income tax asset—current			51,000				99,000
Prepaid drilling expense			975,538				975,538
Prepaid expenses and other current assets			73,349				76,433
Total current assets			4,638,713				3,356,036
PROPERTY AND EQUIPMENT:
Oil and natural gas properties (successful efforts method)			24,050,706				24,434,664
Other equipment			89,248				89,248
Less accumulated depletion and depreciation			(9,267,010	)			(9,318,340	)
Net property and equipment			14,872,944				15,205,572
Total assets		$	19,511,657			$	18,561,608
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses		$	748,843			$	553,760
Oil and gas revenues payable			211,390				198,247
Unrealized loss on commodity derivatives			68,000				—
Total current liabilities			1,028,233				752,007
LONG-TERM DEBT			6,740,000				6,740,000
DEFERRED INCOME TAXES			1,200,000				1,033,000
ASSET RETIREMENT OBLIGATION			1,447,002				1,405,002
Total liabilities			10,415,235				9,930,009
STOCKHOLDERS’ EQUITY:
Common stock, $.01 par value, 75,000,000 shares authorized; 8,910,175 shares issued each period, and 7,997,175 and 8,077,175 outstanding, respectively			89,101				89,101
Additional paid-in capital			4,573,580				4,573,580
Retained earnings			6,365,456				5,577,260
Treasury stock, 913,000 and 833,000 shares, at cost			(1,931,715	)			(1,608,342	)
Total stockholders’ equity			9,096,422				8,631,599
Total liabilities and stockholders’ equity		$	19,511,657			$	18,561,608

See accompanying notes to these unaudited condensed consolidated financial statements.

FieldPoint Petroleum Corporation

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
REVENUE:
Oil and natural gas sales		$	1,878,413			$	1,725,894			$	3,575,958			$	3,532,023
Well operational and pumping fees			17,066				17,066				34,132				34,132
Disposal fees			21,270				26,713				34,270				40,213
Total revenue			1,916,749				1,769,673				3,644,360				3,606,368
COSTS AND EXPENSES:
Production expense			649,139				548,241				1,219,827				1,048,736
Depletion and depreciation			248,000				274,000				491,000				565,000
Accretion of discount on asset retirement obligations			21,000				20,000				42,000				40,000
General and administrative			213,279				249,094				464,924				481,314
Total costs and expenses			1,131,418				1,091,335				2,217,751				2,135,050
OPERATING INCOME			785,331				678,338				1,426,609				1,471,318
OTHER INCOME (EXPENSE):
Interest income			1,181				1,544				2,019				2,560
Interest expense			(61,302	)			(60,516	)			(121,151	)			(123,811	)
Unrealized loss on commodity derivatives			(68,000	)			—				(68,000	)			—
Loss on sale of oil and gas properties			(10,670	)			—				(10,670	)			—
Miscellaneous			(6,611	)			—				(6,611	)			—
Total other income (expense)			(145,402	)			(58,972	)			(204,413	)			(121,251	)
INCOME BEFORE INCOME TAXES			639,929				619,366				1,222,196				1,350,067
INCOME TAX EXPENSE — CURRENT			(130,000	)			(24,000	)			(217,000	)			(192,000	)
INCOME TAX EXPENSE — DEFERRED			(99,000	)			(201,000	)			(217,000	)			(285,000	)
TOTAL INCOME TAX PROVISION			(229,000	)			(225,000	)			(434,000	)			(477,000	)
NET INCOME		$	410,929			$	394,366			$	788,196			$	873,067
EARNINGS PER SHARE:
BASIC		$	0.05			$	0.05			$	0.10			$	0.11
DILUTED		$	0.05			$	0.05			$	0.10			$	0.11
WEIGHTED AVERAGE SHARES OUTSTANDING:
BASIC			8,016,757				8,223,688				8,040,742				8,277,609
DILUTED			8,016,757				8,223,688				8,040,742				8,277,609

See accompanying notes to these unaudited condensed consolidated financial statements.

FieldPoint Petroleum Corporation

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

		For the Six Months Ended
		June 30,
		2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	788,196			$	873,067
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on sale of oil and natural gas properties			10,670				—
Unrealized loss on commodity derivatives			68,000				—
Depletion and depreciation			491,000				565,000
Deferred income tax expense			217,000				285,000
Accretion of discount on asset retirement obligations			42,000				40,000
Changes in current assets and liabilities:
Accounts receivable			(2,098	)			133,903
Prepaid expenses and other assets			(66,916	)			(109,000	)
Accounts payable and accrued expenses			195,083				124,741
Oil and gas revenues payable			13,143				(7,941	)
Other			(2,024	)			(57	)
Net cash provided by operating activities			1,754,054				1,904,713
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties			(237,372	)			(376,468	)
Proceeds from the sale of oil and natural gas properties			68,330				—
Net cash used in investing activities			(169,042	)			(376,468	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Purchase of treasury shares			(323,373	)			(514,071	)
Net cash used in financing activities			(323,373	)			(514,071	)
NET CHANGE IN CASH AND CASH EQUIVALENTS			1,261,639				1,014,174
CASH AND CASH EQUIVALENTS, beginning of the period			984,770				657,942
CASH AND CASH EQUIVALENTS, end of the period		$	2,246,409			$	1,672,116

See accompanying notes to these unaudited condensed consolidated financial statements.

FieldPoint Petroleum Corporation

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Business, Organization and Basis of Preparation and Presentation

FieldPoint Petroleum Corporation (the “Company”, “our”, or “we”) is incorporated under the laws of the state of Colorado. The Company is engaged in the acquisition, operation and development of oil and natural gas properties, which are located in Louisiana, New Mexico, Oklahoma, Texas, and Wyoming.

The condensed consolidated financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted. However, in the opinion of management, all adjustments (which consist only of normal recurring adjustments) necessary to present fairly the financial position and results of operations for the periods presented have been made. You should read these condensed consolidated financial statements in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Form 10-K filing for the year ended December 31, 2010.

2. Earnings Per Share

Basic earnings per share are computed based on the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share take common stock equivalents (such as options and warrants) into consideration. The Company had no dilutive or potentially dilutive common stock equivalents outstanding during the three or six months ended June 30, 2011 or 2010.

3. Income Taxes

For the three and six months ending June 30, 2011, the tax provision is approximately 36% of book income before tax which approximates the statutory federal and state rates.

For the three and six months ending June 30, 2010, the tax provision is approximately 36% and 35%, respectively, of book income before tax which approximates the statutory federal and state rates.

4. Treasury Stock Repurchase Program

We repurchased a total of 63,000 and 80,000 common shares with an aggregate cost of $249,480 and $323,373 during the three and six months ended June 30, 2011.

5. Related Party Transactions

The Company leases office space from its president. Rent expense for this month-to-month lease was $15,000 for each of the six month periods ended June 30, 2011 and 2010 and $7,500 for each of the three month periods ended June 30, 2011 and 2010. The Company also paid Roger Bryant, a director, $2,500 in consulting fees during the six months ended June 30, 2010 and none in 2011.

6. Prepaid Drilling Expense

Prepaid drilling expense includes the amount paid related to a non-operated well expected to be drilled in 2011.

7. Long-Term Debt

Effective June 15, 2011, the borrowing base under our line of credit was decreased from $10,500,000 to $9,250,000.

8. Sale of Property

We sold our Whistler property during the first quarter 2011 for approximately $68,000, which resulted in a loss on the sale of $10,670.

9. Commodity Derivatives

In June 2011, we entered into the following commodity derivatives positions to hedge our oil production price risk. These positions were outstanding at June 30, 2011:

Period		Volume (Barrels)								$/Barrel
		Daily				Total				Floor				Ceiling
NYMEX —WTI Collars July 2011 — December 2011			200				36,800			$	85.00			$	102.50

The following table summarizes the fair value of our open commodity derivatives as of June 30, 2011 and December 31, 2010:

		Liability Derivatives
				Fair Value
		Balance Sheet		June 30,				December 31,
		Location		2011				2010
Derivatives not designated as hedging instruments
Commodity derivatives		Current Liabilities		$	68,000			$	—

The following table summarizes the change in fair value of our commodity derivatives:

				Fair Value
		Income		3 Months Ended								Six Months Ended
		Statement		June 30,								June 30,
		Location		2011				2010				2011				2010
Derivatives not designated as hedging instruments
Commodity derivatives		Other Income (Expense)		$	68,000			$	—			$	68,000			$	—

Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair values of collar contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

We are exposed to credit losses in the event of non-performance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate non-performance by the counterparties over the term of the commodity derivatives positions.

To estimate the fair value of our commodity derivatives positions, we use 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 use the best available information. We determine the fair value based upon the 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. At June 30, 2011, we had no Level 1 measurements

•

Level 2 — Pricing inputs are 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 of commodity 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. At June 30, 2011, all of our commodity derivatives were valued using Level 2 measurements.

•

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. At June 30, 2011, we had no Level 3 measurements.

PART I

Item 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

The following discussion should be read in conjunction with the Company’s Condensed Consolidated Financial Statements, and respective notes thereto, included elsewhere herein. The information below should not be construed to imply that the results discussed herein will necessarily continue into the future or that any conclusion reached herein will necessarily be indicative of actual operating results in the future. Such discussion represents only the best present assessment of the management of FieldPoint Petroleum Corporation.

General

FieldPoint Petroleum Corporation derives its revenues from its operating activities including sales of oil and natural gas and operating oil and natural gas properties. The Company’s capital for investment in producing oil and natural gas properties has been provided by cash flow from operating activities and from bank financing. The Company categorizes its operating expenses into the categories of production expenses and other expenses.

Results of Operations

Comparison of three months ended June 30, 2011 to the three months ended June 30, 2010

		Quarter Ended June 30,
		2011				2010
Revenue:
Oil sales		$	1,725,479			$	1,459,305
Natural gas sales			152,934				266,589
Total oil and natural gas sales		$	1,878,413			$	1,725,894
Sales volumes:
Oil (Bbls)			17,540				19,477
Natural gas (Mcf)			30,348				39,616
Total (BOE)			22,598				26,080
Average sales prices:
Oil ($/Bbl)		$	98.37			$	74.92
Natural gas ($/Mcf)			5.04				6.73
Total ($/BOE)		$	83.12			$	66.18
Costs and expenses ($/BOE)
Lease operating expense		$	28.73			$	21.02
Depletion and depreciation			10.97				10.51
Accretion of discount on asset retirement obligations			0.93				0.77
General and administrative			9.44				9.55
Total		$	50.07			$	41.85

Oil and natural gas sales revenues increased 9% or $152,519 to $1,878,413 for the three-month period ended June 30, 2011 from the comparable 2010 period. Average oil sales prices increased 31% to $98.37 for the three-month period ended June 30, 2011 compared to $74.92 for the period ended June 30, 2010. Average natural gas sales prices decreased 25% to $5.04 for the three-month period ended June 30, 2011 compared to $6.73 for the period ended June 30, 2010. Sales volumes decreased 13% on a BOE basis, primarily due to natural declines and downtime on wells waiting on repair. The overall higher commodity prices account for approximately $360,000 of the increase in revenues but was offset by lower sales volumes of approximately $207,000. We anticipate volumes to remain stable in the coming quarters as additional remedial work is completed.

Lease operating expenses increased 18% or $100,898 to $649,139 for the three month period ended June 30, 2011 from the comparable 2010 period. This was primarily due to increases in workover expense and remedial repairs in 2011 as compared to 2010. The decreased volumes account for approximately $73,000 of decrease in lease operating expenses. Lifting costs per BOE increased 37% or $7.71 to $28.73 for the period. We anticipate lease operating expenses to increase over the following quarters due to additional remedial repairs and workover expenses.

Depletion and depreciation decreased 9% or $26,000 to $248,000 for the three month period ended June 30, 2011 versus $274,000 in the 2010 comparable period. This was primarily due to lower production during the quarter ended June, 30, 2011 as compared to the same period in 2010.

General and administrative overhead cost decreased 14% or $35,815 to $213,279 for the three-month period ended June 30, 2011 from the three-month period ended June 30, 2010. This was primarily attributable to a decrease in legal, consulting and administration services during the 2011 period. At this time, the Company anticipates general and administrative expenses to increase in the coming quarters.

Other expenses, net for the quarter ended June 30, 2011, were $145,402 compared to $58,972 for 2010. The net increase was primarily due to a $68,000 unrealized loss on commodity derivatives and a $10,670 loss on the sale of oil and natural gas properties during the 2011 period.

Results of Operations

Comparison of Six Months Ended June 30, 2011 to the Six Months Ended June 30, 2010

		Six Months Ended June 30,
		2011				2010
Revenues:
Oil sales		$	3,284,677			$	3,003,834
Natural gas sales			291,281				528,189
Total		$	3,575,958			$	3,532,023
Sales volumes:
Oil (Bbls)			34,010				39,736
Natural gas (Mcf)			55,219				81,315
Total (BOE)			43,213				53,288
Average sales prices
Oil ($/Bbl)		$	96.58			$	75.59
Natural gas ($/Mcf)			5.28				6.49
Total ($/BOE)		$	82.75			$	66.28
Costs and expenses ($/BOE)
Lease operating expense		$	28.23			$	19.68
Depletion and depreciation			11.36				10.60
Accretion of discount on asset retirement obligations			0.97				0.75
General and administrative			10.76				9.03
Total		$	51.32			$	40.07

Oil and natural gas sales revenues increased 1% or $43,935 to $3,575,958 for the six month period ended June 30, 2011 from $3,532,023 for the comparable 2010 period. This was due primarily to the overall increase in oil and natural gas commodity pricing offset by a decline in production. Sales volumes decreased 19% on a BOE basis primarily due to downtime on wells waiting for repairs and to natural declines. Average oil sales prices increased 28% to $96.58 for the six month period ended June 30, 2011 compared to $75.59 for the six month period ended June 30, 2010. Average natural gas sales prices decreased 19% to $5.28 for the six month period ended June 30, 2011 compared to $6.49 for the six month period ended June 30, 2010. The higher commodity prices accounted for an increase of approximately $646,000 in revenue but were offset by approximately $602,000 as a result of lower sales volumes. We anticipate volumes to remain stable in the coming quarters as additional remedial work is completed.

Lease operating expenses increased 16% or $171,091 to $1,219,827 for the six month period ended June 30, 2011 from the comparable 2010 period. This was primarily due to the increase in additional repairs and workover expenses on properties in 2011. Lifting cost per BOE increased 43%, from $19.68 to $28.23 for the period. We anticipate lease operating expense to increase over the following quarters due to additional remedial repairs and workover expenses.

Depletion and depreciation expense decreased 13% to $491,000, compared to $565,000 for the comparable 2009 period. This was primarily due to lower production during the 2011 period.

General and administrative overhead cost decreased 3% or $16,390 to $464,924 for the six month period ended June 30, 2011 from the six month period ended June 30, 2010. This was attributable primarily to a decrease in administrative services such as contract labor and administrative services. In the coming quarters we anticipate general and administrative expenses to increase.

Other expenses, net for the six months ended June 30, 2011, amounted to $204,413 compared to other expenses, net of $121,251 for the comparable 2010 period. The net increase was primarily due to a $68,000 unrealized loss on commodity derivatives and a $10,670 loss on the sale of oil and natural gas properties during the 2011 period.

Liquidity and Capital Resources

Cash flow provided by operating activities was $1,754,054 for the six-month period ended June 30, 2011, as compared to $1,904,713 of cash flow provided by operating activities in the comparable 2010 period. The decrease in cash from operating activities was primarily due to a decrease in net income and changes in prepaid expenses and other assets.

Cash flow used in investing activities was $169,042 for the six-month period ended June 30, 2011 and $376,468 used in the comparable period due to the additions to oil and natural gas properties in each period.

Cash flow used in financing activities was used to repurchase 80,000 shares of common stock for a total of $323,373 during the six-month period ended June 30, 2011. Cash flow used in financing activities for the period ending June 30, 2010 was used to repurchase 200,000 shares of common stock for a total of $514,071.

We may continue to raise financing through draws from our line of credit. Effective June 15, 2011, the borrowing base under our line of credit with Citibank, N.A. was decreased to $9.25 million from $10.5 million. We anticipate our operating cash flow and other capital resources, including our Citibank revolving credit facility, if needed, will adequately fund planned capital expenditures and other capital uses over the near term. Based on industry outlook for the remainder of 2011, prices for oil and natural gas could remain higher than the prior year.

PART I

Item 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We periodically enter into certain commodity price risk management transactions to manage our exposure to oil and natural gas price volatility. These transactions may take the form of futures contracts, swaps or options. All data relating to our derivative positions is presented in accordance with authoritative guidance. Accordingly, unrealized gains and losses related to the change in fair value of derivative contracts that qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss and such amounts are reclassified to oil and natural gas sales revenues as the associated production occurs. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk management activities. At June 30, 2011, we had collars with a floor of $85.00 and a ceiling of $102.50 for 200 barrels of oil per day from July 1, 2011 to December 31, 2011. At June 30, 2010, there were no open positions. We have an unrealized loss of $68,000 on commodity derivative transactions during the three-month or six-month periods ending June 30, 2011. There were no derivative transactions in 2010.

PART I

Item 4. CONTROLS AND PROCEDURES

a)		Disclosure Controls and Procedures
		The Company’s Principal Executive Officer and Principal Financial Officer, Ray Reaves, has established and is currently maintaining disclosure controls and procedures for the Company. The disclosure controls and procedures have been designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that it files 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 the Company is accumulated and communicated to the Company’s management as appropriate to allow timely decisions regarding required disclosure.
		The Principal Executive Officer and Principal Financial Officer conducted a review and evaluation of the effectiveness of the Company’s disclosure controls and procedures and have concluded, based on his evaluation as of the end of the period covered by this Report, that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed 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 the Company is accumulated and communicated to management, including our principal executive officer and our principal financial officer, to allow timely decisions regarding required disclosure and we refer you to Exchange Act Rule 13a-15(e).
b)		Changes in Internal Control over Financial Reporting
		There has been no change in our internal control over financial reporting during the second quarter ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

c)		Limitations of Any Internal Control Design
		Our principal executive and financial officer do not expect that our disclosure controls or internal controls will prevent all error and all fraud. Although our disclosure controls and procedures were designed to provide reasonable assurance of achieving their objectives and our principal executive and financial officer have determined that our disclosure controls and procedures are effective at doing so, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute assurance that the objectives of the system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented if there exists in an individual a desire to do so. There can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

PART II

OTHER INFORMATION

Item 1.		Legal Proceedings

None.

Item 1A.		Risk Factors

None.

Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds

There were no unregistered sales of equity securities during the period ended June 30, 2011. The following table sets forth our repurchases in market transactions of shares of our common stock during the periods ended June 30, 2011:

ISSUER PURCHASES OF EQUITY SECURITIES

														(d) Maximum
														Number (or
														Approximate
										(c) Total Number				Dollar Value) of
										of Shares (or				Shares (or Units)
										Units) Purchased				that May Yet Be
		(a) Total Number of				(b) Average Price				as Part of Publicly				Purchased Under
		shares (or Units)				Paid per Share (or				Announced Plans				the Plans or
Period		Purchased				Unit)				or Programs				Programs
4/1/11 — 4/30/11			38,000			$	4.37				38,000			$	84,391
5/1/11 — 5/31/11			23,000			$	3.35				23,000			$	7,443
6/1/11 — 6/30/11			2,000			$	3.32				2,000			$	797
TOTAL			63,000								63,000

Item 3.		Default Upon Senior Securities

None.

Item 4.		Submission of Matters to a Vote of Security Holders

None.

Item 5.		Other Information

None.

Item 6.		Exhibits

Exhibits
	31			Certification
	32			Certification Pursuant to U.S.C. Section 1350

SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: August 12, 2011		By:		/s/ Ray Reaves   Ray Reaves, President, Chief Executive Officer,
				Treasurer and Chief Financial Officer