Osage Exploration & Development 10Q 2014 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2014

[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE EXCHANGE ACT

For the transition period from __________ to __________

OSAGE EXPLORATION AND DEVELOPMENT, INC.
(Exactname of small business issuer as specified in its charter)

Delaware	0-52718	26-0421736
(State or other jurisdiction of	(Commission	(I.R.S. Employer
incorporation or organization)	File No.)	Identification No.)

2445 5^th Avenue

Suite 310

San Diego, CA 92101

(619) 677-3956

(Address of principal executive offices)

(Issuer’s telephone number)

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 month (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [X] No [ ]

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

Yes [ ] No [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer [ ] Accelerated Filer [ ]

Non-Accelerated Filer [ ] Smaller Reporting Company [X]

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

Yes [ ] No [X]

The number of outstanding shares of the registrant’s common stock, $0.0001 par value, as of August 12, 2014 was 58,098,014.

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements	F-1

	Consolidated Balance Sheets; June 30, 2014 (unaudited) and December 31, 2013	F-1
	Consolidated Statements of Operations and Other Comprehensive Income (Loss); Three and Six Months ended June 30, 2014 (unaudited) and 2013 (unaudited)	F-2
	Consolidated Statements of Cash Flows; Six Months ended June 30, 2014 (unaudited) and 2013 (unaudited)	F-3
	Notes to Consolidated Financial Statements	F-4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	12
Item 4.	Controls and Procedures	12

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	13
Item 1.A.	Risk Factors	13
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	13
Item 3.	Default upon Senior Securities	13
Item 4.	Mine Safety Disclosures	13
Item 5.	Other Information	13
Item 6.	Exhibits	13
Signatures		14

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

As of June 30, 2014 (Unaudited) and December 31, 2013

	June 30, 2014			December 31, 2013
ASSETS

Current assets:
Cash and equivalents	$	10,281,446		$	2,782,643
Accounts receivable		1,901,042			2,769,414
Prepaid expenses and other current assets		84,137			596,742
Deferred financing costs		1,390,642			1,829,124
Total current assets		13,657,267			7,977,923

Property and equipment, at cost:
Oil & gas properties and equipment (successful efforts method)		39,815,424			27,339,460
Other property & equipment		259,025			85,746
		40,074,449			27,425,206
Less: accumulated depletion, depreciation and amortization		(5,028,695	)		(2,683,085	)
		35,045,754			24,742,121

Restricted cash		870,965			908,645
Total assets	$	49,573,986		$	33,628,689

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	3,883,853		$	555,784
Joint interest billing		2,629,212			-
Accrued expenses		671,992			117,800
Unrealized losses on oil and gas derivatives		669,047			265,961
Capital lease liability, current portion		42,272			-
Notes payable		25,000,000			20,000,000
Total current liabilities		32,896,376			20,939,545

Unrealized losses on oil and gas derivatives, net of current portion		-			91,606
Capital lease liability, net of current portion		71,141			-
Liability for asset retirement obligations		4,541			3,886
Total liabilities		32,972,058			21,035,037

Commitments and contingencies

Stockholders’ Equity:
Preferred stock, $0.0001 par value, 10,000,000 authorized, none issued and outstanding as of June 30, 2014 or December 31, 2013		-			-
Common stock, $0.0001 par value, 190,000,000 shares authorized; 58,098,014 and 49,854,675 shares issued and outstanding as of June 30, 2014 and December 31, 2013, respectively		5,809			4,985
Additional paid-in capital		26,243,475			16,903,147
Stock purchase notes receivable		(95,000	)		(95,000	)
Accumulated deficit		(9,552,356	)		(4,219,480	)
Total stockholders’ equity		16,601,928			12,593,652
Total liabilities and stockholders’ equity	$	49,573,986		$	33,628,689

The accompanying notes are an integral part of these unaudited consolidated financial statements.

F-1

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE INCOME (LOSS)

For Three and Six Months Ended June 30, 2014 and 2013 (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013

Operating revenues
Oil revenues	$	1,895,201		$	1,220,811		$	4,028,018		$	2,308,650
Natural gas revenues		583,495			96,782			1,088,093			220,815
Total operating revenues		2,478,696			1,317,593			5,116,111			2,529,465

Operating costs and expenses
Operating costs		390,699			356,489			863,841			538,860
General and administrative expenses		3,643,408			549,133			4,487,360			1,392,843
Depreciation, depletion and accretion		1,346,123			344,527			2,346,022			615,012
Loss on disposal of fixed assets

Total operating costs and expenses		5,380,230			1,250,149			7,697,223			2,546,715

Operating income (loss)		(2,901,534	)		67,444			(2,581,112	)		(17,250	)

Other income (expenses):
Interest income		4,409			1,023			4,833			1,140
Interest expense		(1,215,579	)		(1,129,640	)		(2,426,139	)		(1,896,146	)
Loss on oil and gas derivatives		(362,995	)		(36,690	)		(478,722	)		(36,690	)
Gain on sale of land interests		77,950			-			148,264			-

Loss from continuing operations before income taxes		(4,397,749	)		(1,097,863	)		(5,332,876	)		(1,948,946	)
Provision for income taxes		-			-			-			-
Loss from continuing operations		(4,397,749	)		(1,097,863	)		(5,332,876	)		(1,948,946	)
Discontinued operations:
Income from discontinued operations net of income taxes		-			1,128,565			-			1,906,223

Net income (loss)		(4,397,749	)		30,702			(5,332,876	)		(42,723	)

Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment attributable to discontinued operations		-			(849	)		-			22,714

Comprehensive income (loss)	$	(4,397,749	)	$	29,853		$	(5,332,876	)	$	(20,009	)

Basic and diluted income (loss) per share
Continuing operations	$	(0.08	)	$	(0.02	)	$	(0.10	)	$	(0.04	)
Discontinued operations	$	-		$	0.02		$	-		$	0.04

Weighted average number of common share and common share equivalents used to compute basic and diluted income (loss) per share		58,033,570			49,804,453			54,817,975			49,645,119

The accompanying notes are an integral part of these unaudited consolidated financial statements.

F-2

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

For Six Months Ended June 30, 2014 and 2013

	2014			2013
Cash flows from operating activities:
Net loss	$	(5,332,876	)	$	(42,723	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Stock based compensation		3,032,252			405,500
Amortization of deferred financing costs		538,482			641,424
Amortization of debt discount		-			91,415
Gain on sale of land interests		(148,264	)		-
Write off of expired mineral rights leases		13,373			15,283
Accretion of asset retirement obligation		412			4,731
Provision for depletion, depreciation and amortization		2,345,610			714,899
Unrealised loss on oil and gas derivatives		311,480			36,690
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		868,372			(1,612,442	)
Decrease in prepaid expenses and other current assets		512,605			18,497
(Decrease) increase in accounts payable		(236,819	)		132,154
Increase in joint interest billing account		2,629,212			-
Increase (decrease) in accrued expenses		554,192			(907,619	)
Net cash provided by (used in) operating activities		5,088,031			(502,191	)

Cash flows from investing activities:
Investments in oil & gas properties		(9,115,107	)		(9,957,828	)
Investments in non-oil & gas properties		(45,844	)		-
Decrease (increase) in restricted cash		37,680			(114,800	)
Net proceeds from sale of land interests		339,165			16,846
Proceeds from notes receivable		-			6,000
Net cash used in investing activities		(8,784,106	)		(10,049,782	)

Cash flows from financing activities:
Proceeds from offering of securities		6,744,000			-
Proceeds from secured promissory notes		5,000,000			10,000,000
Proceeds from term loan		-			367,520
Principal payments on term loan		-			(92,147	)
Principal payments on capital leases		(14,022	)		-
Payment of placement fees and expenses		(437,100	)		-
Payment of deferred financing costs		(100,000	)		(100,000	)
Proceeds from exercise of warrants		2,000			3,500
Net cash provided by financing activities		11,194,878			10,178,873

Effect of exchange rate on cash and equivalents		-			131,043

Net increase in cash and equivalents		7,498,803			(242,057	)

Cash and equivalents - beginning of period		2,782,643			486,205

Cash and equivalents - end of period	$	10,281,446		$	244,148

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payment for interest	$	1,887,657		$	1,179,761
Cash payment for income taxes	$	-			-

SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Increase in asset retirement obligation	$	243		$	25
Purchase of furniture and fixtures through capital leases	$	127,435		$	-
Oil and gas additions in accounts payable	$	3,564,888		$	2,716,579

The accompanying notes are an integral part of these unaudited consolidated financial statements.

F-3

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2014 and 2013 (unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

Osage Exploration and Development, Inc. (“Osage” or the “Company”) is an independent energy company engaged primarily in the acquisition, development, production and sale of oil, natural gas and natural gas liquids. The Company’s production activities are located in the State of Oklahoma. The principal executive offices of the Company are at 2445 Fifth Avenue, Suite 310, San Diego, CA 92101.

Osage prepared the accompanying unaudited consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) instructions to Form 10-Q and Item 310(b) of Regulation S-K. These financial statements should be read together with the financial statements and notes in the Company’s 2013 Form 10-K filed with the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP were condensed or omitted. The accompanying financial statements reflect all adjustments and disclosures, which, in the Company’s opinion, are necessary for fair presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the entire year.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Going Concern

As a result of production delays outside of the Company’s control, the Company was not in compliance with certain covenants as of June 30, 2014 and March 31, 2014, including the minimum production covenant under the senior secured note purchase agreement (see Note 5 - Debt).

On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation. On April 5, 2013 we amended this agreement, increasing the facility to $20,000,000 and on April 7, 2014 we further amended this agreement, increasing the facility to $30,000,000, extending the term of the facility by one year, reducing the interest rate from Libor plus 15% to Libor plus 11% and agreeing to modify the covenants to reflect the transition from participant to operator. The Company also drew down an additional $5,000,000. The Company and the lender are still in discussions about modifications to the covenants and the existing covenants, some of which the Company is not in compliance with, remain in place until new covenants are agreed upon.

In the six months ended June 30, 2014, the Company raised approximately $6.7 million of gross proceeds in a private placement. (See Note 10 - Equity)

Management of the Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond. These steps include (a) becoming operators of our own wells, (b) participating in drilling of wells in Logan County, Oklahoma, (c) controlling overhead and expenses, and (d) raising additional equity and/or debt.

The Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s ability to continue as a going concern is dependent upon achieving profitable operations and obtaining additional financing. There is no assurance additional funds will be available on acceptable terms or at all. This raises substantial doubt about the Company’s ability to continue as a going concern.

These consolidated financial statements do not give effect to any adjustments which would be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and discharge its liabilities in other than the normal course of business and at amounts different from those reflected in the accompanying consolidated financial statements.

Basis of Consolidation

The consolidated financial statements include the accounts of Osage and its wholly owned subsidiaries, Osage Energy Company, LLC and Osage Exploration and Development Operating, LLC. Accordingly, all references herein to Osage or the Company include the consolidated results. All significant inter-company accounts and transactions were eliminated in consolidation. The results, assets and liabilities of the Company’s former wholly owned subsidiary, Cimarrona, LLC, have been presented as discontinued operations in the consolidated financial statements.

F-4

Use of Estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Management used significant estimates in determining the carrying value of its oil and gas producing assets and the associated depreciation and depletion expense related to sales volumes. The significant estimates include the use of proved oil and gas reserve estimates and the related present value of estimated future net revenues therefrom.

Reclassifications

Certain amounts included in the prior year financial statements have been reclassified to conform to the current year’s presentation. These reclassifications have no affect on the reported results in 2014 or 2013.

Risk Factors Related to Concentration of Sales and Products

The Company’s future financial condition and results of operations depend upon prices received for its oil and natural gas and the costs of finding, acquiring, developing and producing reserves. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer product demand and the price and availability of alternative fuels.

Cash and Equivalents

Cash and equivalents consist of short-term, highly liquid investments readily convertible into cash with an original maturity of three months or less.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk are cash and accounts receivable arising from its normal business activities. The Company places its cash in what it believes are credit-worthy financial institutions. However, the Company’s cash balances have exceeded the FDIC insured levels at various times during the three and six months ended June 30, 2014 and 2013. The Company maintains cash accounts only at large, high quality financial institutions and believes the credit risk associated with cash held in banks exceeding the FDIC insured levels is remote. The Company generated substantially all of its revenues from six customers in the three and six months ended June 30, 2014 and four customers in prior year comparable quarter.

Deferred Financing Costs

The Company incurred deferred financing costs in connection with the Note Purchase Agreement (see Note 5), which represented the fair value of warrants, placement fees and legal fees. Deferred financing costs of $3,959,448 are being amortized over the term of the Note Purchase Agreement on a straight-line basis, which approximates the effective interest method.

Deferred financing costs net of accumulated amortization at June 30, 2014 were $1,390,642. Amortization of deferred financing costs was $190,499 and $538,482 for the three and six months ended June 30, 2014, respectively and $326,962 and $641,424 for the three and six months ended June 30, 2013, respectively.

F-5

Restricted Cash

In connection with the Apollo Note Purchase Agreement, as amended (see Note 5), the Company has classified $812,500 and $850,000, representing three months interest, as restricted cash as of June 30, 2014 and December 31, 2013, respectively. The Company has also pledged $58,465 for certain bonds and sureties at June 30, 2014. Restricted cash at June 30, 2014 was $870,965, compared to $908,645 at December 31, 2013.

Risk Management Activities

The Company has entered into certain derivative financial instruments to manage the inherent uncertainty of future revenues. The Company does not intend to hold or issue derivative financial instruments for speculative purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment. These derivative financial instruments are marked to market at each reporting period.

Net Income/Loss Per Share

In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 260 “Earnings Per Share,” the Company’s basic net income/loss per share of common stock is calculated by dividing net income/loss by the weighted-average number of shares of common stock outstanding for the period. The diluted net income/loss per share of common stock is computed by dividing the net income/loss using the weighted-average number of common shares including potential dilutive common shares outstanding during the period. Potential common shares are excluded from the computation of diluted net loss per share if anti-dilutive.

The following table shows the computation of basic and diluted net income (loss) per share for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013

Net loss allocable to continuing operations	$	(4,397,749	)	$	(1,097,863	)	$	(5,332,876	)	$	(1,948,946	)
Net income allocable to discontinued operations	$	-		$	1,128,565		$	-		$	1,906,223

Basic and diluted net income (loss) per share
Continuing operations	$	(0.08	)	$	(0.02	)	$	(0.10	)	$	(0.04	)
Discontinued operations	$	-		$	0.02		$	-		$	0.04

Basic and diluted weighted average shares outstanding		58,033,570			49,804,453			54,817,975			49,645,119

Potential common shares consisted of 7,287,559 and 1,696,843 warrants and options to purchase common stock at June 30, 2014 and 2013, respectively. All of these warrants and options were excluded from the computations for the three and six months June 30, 2014 and 2013, as their effect would have been anti-dilutive.

Fair Value of Financial Instruments

As of June 30, 2014 and December 31, 2013, the fair value of cash and equivalents, accounts receivable, notes payable, accounts payable and accrued expenses approximate carrying values because of the short-term maturity of these instruments.

FASB ACS Topic 820, “Fair Value Measurements and Disclosures,” requires disclosure of the fair value of financial instruments held by the Company. ASC Topic 825, “Financial Instruments,” defines fair value, and establishes a three-level valuation hierarchy for disclosures of fair value measurement that enhances disclosure requirements for fair value measures. The carrying amounts reported in the consolidated balance sheets for receivables and current liabilities each qualify as financial instruments and are a reasonable estimate of their fair value because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest.

The three levels of valuation hierarchy are defined as follows:

	●	Level 1 inputs to the valuation methodology are quoted prices 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, quoted prices for identical or similar assets in inactive markets, and inputs that 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 use one or more unobservable inputs which are significant to the fair value measurement.

F-6

The Company analyzes all financial instruments with features of both liabilities and equity under ASC Topic 480, “Distinguishing Liabilities from Equity,” and ASC Topic 815, “Derivatives and Hedging.”

As of June 30, 2014 the Company identified certain derivative financial instruments which required disclosure at fair value on the balance sheet.

The following table presents information for those assets and liabilities requiring disclosure at fair value as of 2014:

Total

Fair Value Measurements Using:

Carrying

Fair

Level 1

Level 2

Level 3

Amount

Value

Inputs

June 30, 2014 assets (liabilities):

Commodity derivative liability

(669,047

)

(669,047

)

(669,047

)

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 2 Fair Value Measurements

Commodity derivatives — The fair values of commodity derivatives are estimated using internal option pricing models based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

Recent Accounting Pronouncements

The Company does not expect the adoption of any recently issued accounting pronouncements to have a material effect on the consolidated financial statements.

3. OIL AND GAS PROPERTIES

Oil and gas properties consisted of the following:

	June 30, 2014			December 31, 2013

Properties subject to amortization	$	38,207,374		$	25,551,336
Properties not subject to amortization		1,604,149			1,784,465
Capitalized asset retirement costs		3,901			3,659
Accumulated depreciation and depletion		(4,933,502	)		(2,606,243	)
Oil & gas properties, net	$	34,881,922		$	24,733,217

Depreciation and depletion expense for oil and gas properties totaled $1,334,307 and $2,327,259 in the three and six months ended June 30, 2014 and 2013, respectively and $213,128 and $478,733 in the three and six months ended June 30, 2013, respectively.

On December 12, 2013, Osage and Slawson entered into an agreement (the “Partition Agreement”) which amended the Participation Agreement related to certain lands located within the Nemaha Ridge in Logan County, Oklahoma, and for the exploration and development of those leases by the parties.

Under the Partition Agreement and effective as of September 1, 2013, Slawson agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Slawson, such that the net acreage controlled by the parties would remain substantially unchanged, but that the acreage controlled by each of the parties in undeveloped sections would be located in sections where the other party did not control acreage. The parties also agreed that the Participation Agreement would terminate as to all lands within the Nemaha Ridge Project except for lands within sections already developed by the parties which shall continue to be controlled by the Participation Agreement.

F-7

As a result of the Partition Agreement, Osage has become the project operator on much of its acreage in the Nemaha Ridge Project. As of June 30, 2014, Osage operated or has the right to operate approximately 4,183 net acres (6,301 gross), and remains joint-venture or potential joint-venture partners with others in approximately 5,185 net acres (30,088 gross).

In 2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, we purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect targeting the Mississippian, for $8,500. In addition, B&W is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first $200,000 of lease bonus paid in the form of an assignment of 12.5% of the leases acquired. Subsequently, B&W shall have an option to purchase a 12.5% share of leasehold acquired on a heads-up basis. As of June 30, 2014, the Company had 4,190 net acres (5,085 gross) leased in Pawnee County. As of June 30, 2014, none of these leases have been assigned to B&W.

In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Oily Woodford Shale formation. The Oily Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Oily Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At June 30, 2014, we had 4,246 net (9,509 gross) acres leased in Coal County.

At June 30, 2014 we have leased 17,804 net (50,983 gross) acres across three counties in Oklahoma as follows:

	Gross		Osage Net
Logan (non operated)		30,088		5,185
Logan - Osage		6,301		4,183
Coal		9,509		4,246
Pawnee		5,085		4,190
		50,983		17,804

4. SEGMENT AND GEOGRAPHICAL INFORMATION

At June 30, 2014, the Company’s continuing operations comprised one segment in one geographic region.

5. DEBT

Apollo - Note Purchase Agreement

On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement” or “Notes”) with Apollo Investment Corporation (“Apollo”). The Notes, which mature on April 27, 2015, are secured by substantially all of the assets of the Company, including a mortgage on all our Oklahoma leases. The Notes bear interest of Libor plus 15.0% with a Libor floor of 2.0%, with interest payable monthly. In addition, Apollo received a warrant to purchase 1,496,843 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and an expiration date of April 27, 2017. Variables used in the valuation include (1) discount rate of 0.82%, (2) expected life of 5 years, (3) expected volatility of 245.0% and (4) zero expected dividends. The minimum draw amount on the Note Purchase Agreement is $1,000,000. At closing, we did not draw down any funds.

At closing of the Note Purchase Agreement, we paid $100,000 of a minimum placement fee to CC Natural Resource Partners, LLC (“CCNRP”) and issued a warrant to purchase 250,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and an expiration date of April 27, 2014. Variables used in the valuation include (1) discount rate of 0.26%, (2) expected life of 2 years, (3) expected volatility of 242.0% and (4) zero expected dividends. In addition, we paid $170,692 in legal fees, of which $100,000 were paid to Apollo. In December 2012, we paid an additional $380,000 in placement fees. We also issued a warrant to purchase 100,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $89,952 and a term of five years, to the placement agent for the Note Purchase Agreement and amended the term of the warrant granted on April 27, 2012 from two to five years, with a Black-Scholes value of $1,161. Variables used in the valuation include (1) discount rate of 0.72%, (2) expected life of five years, (3) expected volatility of 242.0% and (4) zero expected dividends. In December 2013 we paid an additional $100,000 in placement fees and in April 2014 we paid $100,000 in additional placement fees.

On April 5, 2013 the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the facility to $20,000,000 and modifying certain covenants for the remainder of the Note Purchase Agreement term. The Company paid an amendment fee of $100,000 which is being amortized over the remaining term of the Note Purchase Agreement.

F-8

On August 12, 2013, the Company and Apollo amended the Note Purchase Agreement. The amendment required that the Company, within 75 days of the effective date as defined in the amendment, complete either (1) a sale of certain assets, or (2) the issuance of capital stock in a transaction that resulted in aggregate net proceeds as defined in the amendment. In the event that the Company did not complete either one of the aforementioned transactions, the Company would have been required under the terms of the amendment to issue to Apollo additional warrants equivalent to three percent of the Company’s common stock, on a fully-diluted basis. On October 7, 2013, the Company completed the sale of its membership interests in Cimarrona LLC as more fully discussed in Note 11. This sale satisfied the requirements of the amendment and the Company is thus not obligated to issue additional Warrants to Apollo.

During the quarter ended June 30, 2014, we drew down $5,000,000 in additional funds and, as of June 30, 2014, the amount outstanding under the Note Purchase Agreement was $25,000,000. On April 3, 2014, the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the total facility to $30,000,000, extending the term by one year and reducing the interest rate from Libor plus 15% to Libor plus 11%. The parties also agreed to modify future covenants to reflect the Company’s transition from participant to operator.

The Company has recorded deferred financing costs in the aggregate amount of $3,959,448 in connection with the Note Purchase Agreement, which represented the fair value of warrants issued to Apollo and CCNRP, placement fees, amendment fees and legal fees, which are amortized on a straight-line basis over the term of the Notes, which approximates the effective interest method, as the Company did not draw funds at issuance.

On each anniversary of the closing date, the Company is obligated to pay an administrative fee of $50,000. The Company is subject to certain precedents in connection with each draw, an upfront fee equal to 2.0% of the principal amount of each draw, and is required to maintain a deposit account equal to three months of interest payments.

The Company is subject to various affirmative, negative and financial covenants under the Note Purchase Agreement as amended along with other restrictions and requirements, all as defined in the Note Purchase Agreement. Affirmative covenants include by October 31st of each year beginning in 2012, a reserve report prepared as of the immediately preceding September 30, concerning the Company’s domestic oil and gas properties prepared by approved petroleum engineers, and thereafter as of September 30th of each year.

The Company and Apollo are negotiating new covenants to the Note Purchase Agreement. Until these negotiations are complete existing covenants, some of which the Company is not in compliance with, remain in place. Accordingly, the Company has classified borrowings under the Note Purchase Agreement as short term in the accompanying consolidated balance sheets.

Use of proceeds is limited to those purposes specified in the Note Purchase Agreement. The Notes are subject to mandatory prepayment in the event of certain asset sales, insurance or condemnation proceeds, issuance of indebtedness, extraordinary receipts and tax refunds. All terms are as defined in the Note Purchase Agreement.

Boothbay - Secured Promissory Note

On April 17, 2012, we issued a secured promissory note (“Secured Promissory Note”) to Boothbay Royalty Co., (“Boothbay”) for gross proceeds of $2,500,000. The Secured Promissory Note had a maturity date of April 17, 2014 and bore interest of 18%, payable monthly. In addition, Boothbay received 400,000 shares of common stock for which the relative fair value of $386,545 was recorded as debt discount, a 1.5% overriding royalty on our leases in section 29, township 17 North, range 3 and a 1.7143% overriding royalty on our leases in section 36, township 19 North, range 4 West in Logan County, Oklahoma. The closing price of the Company’s common stock on April 17, 2012 was $1.14. The Secured Promissory Note was secured by a first mortgage (with power of sale), security agreement and financing statement covering a 5% overriding royalty interest, proportionately reduced, in all of the Company’s leases in Logan County, Oklahoma. The Company repaid the Secured Promissory Note in full in December 2013.

In connection with the Note Purchase Agreement, the Company recognized $1,215,360 of interest expense, of which $190,499 was non-cash interest expense and $1,024,861 was cash interest expense, for the three months ended June 30, 2014. For the six months ended June 30, 2014, the Company recognized $2,425,920 of interest expense related to this facility, of which $538,482 was non-cash interest expense and $1,887,438 was cash interest expense. In connection with the Note Purchase Agreement and the Secured Promissory Note, the Company recognized $1,129,640 of interest expense, of which $375,112 was non-cash interest expense and $754,528 was cash interest expense, for the three months ended June 30, 2013. For the six months ended June 30, 2013, the Company recognized $1,896,116 of interest expense related to these facilities, of which $732,839 was non-cash interest expense and $1,163,306 was cash interest expense.

F-9

6. DERIVATIVE FINANCIAL INSTRUMENTS

The Company entered into certain derivative financial instruments with respect to a portion of its oil and gas production in the third quarter of 2013. Prior thereto, the Company had not entered into any derivative financial instruments. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility and currently include only costless price collars. The Company does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.

As of June, 2014, the Company had the following open oil derivative positions. These oil derivatives settle against the average of the daily settlement prices for the WTI first traded contract month on the New York Mercantile Exchange (“NYMEX”) for each successive day of the calculation period.

	Price Collars
	Monthly		Weighted Average		Weighted Average
	Volume		Floor Price		Ceiling Price
Period		(BBLs/m)		($/BBL)		($/BBL)

Q3 - Q4, 2014		6,000	$	85.00	$	95.00
Q1 - Q2, 2015		6,000	$	80.00	$	93.50

As of June 30, 2014, the Company had the following open natural gas derivative positions. These natural gas derivatives settle against the NYMEX Penultimate for the calculation period.

	Price Collars
	Monthly		Weighted Average		Weighted Average
	Volume		Floor Price		Ceiling Price
Period	(Btu/m)		($/Btu)		($/Btu)

Q3 - Q4, 2014		10,000	$	3.75	$	4.40
Q1 - Q2, 2015		10,000	$	3.75	$	4.40

Cash settlements and unrealized gains and losses on fair value changes associated with the Company’s commodity derivatives are presented in the “Oil and gas derivatives’ caption in the accompanying consolidated statements of earnings.

The following table sets forth the cash settlements and unrealized gains and losses on fair value changes for commodity derivatives for the three and six months ended June 30, 2014 and 2013.

	Three Months Ended			Six Months Ended
	June 30, 2014			June 30, 2014

Cash settlements to (by) Company	$	(119,572	)	$	(167,242	)
Unrealized gains (losses) on commodity derivatives		(243,423	)		(311,480	)
Loss on oil and gas derivatives	$	(362,995	)	$	(478,722	)

	Three Months Ended			Six Months Ended
	June 30, 2013			June 30, 2013

Cash settlements to (by) Company	$	-		$	-
Unrealized gains (losses) on commodity derivatives		(36,690	)		(36,690	)
Loss on oil and gas derivatives	$	(36,690	)	$	(36,690	)

On October 15, 2013, the Company entered into an Intercreditor Agreement with Apollo and BP Energy Company to provide collateral for its oil and gas derivative financial instruments. BP Energy Corporation North America simultaneously provided a Guarantee for $25 million as collateral for its obligations to the Company.

F-10

7. COMMITMENTS AND CONTINGENCIES

Environment

Osage, as owner and operator of oil and gas properties, is subject to various Federal, State, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the owner of real property and the lessee under oil and gas leases for the cost of pollution clean-up resulting from operations, subject the owner/lessee to liability for pollution damages and impose restrictions on the injection of liquids into subsurface strata. Although Company environmental policies and practices are designed to ensure compliance with these laws and regulations, future developments and increasing stringent regulations could require the Company to make additional unforeseen environmental expenditures. The Company maintains insurance coverage it believes is customary in the industry, although it is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of June 30, 2014, that would have a material impact on its consolidated financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s property.

Operating Leases

In February 2011, the Company entered into a 36 month lease for its corporate offices in San Diego. In February 2014, the Company amended this lease to extend the term for an additional three years through February 2017. In February 2012, the Company entered into a 24 month lease for a vehicle to be utilized by its operations in Oklahoma and entered into a 36 month lease for a vehicle at the termination of the original auto lease. In December 2013, the Company entered into a three year lease for office space in Oklahoma City the term for which commenced in February 2014.

Rental expense totaled $44,028 and $14,595 in the three months ended June 30, 2014 and 2013, respectively and $74,967 and $28,958 for the six months ended June 30, 2014 and 2013, respectively.

Future minimum commitments under operating leases are as follows as of June 30, 2014:

Year	Amount

2014 (July - December)	$	91,883
2015		184,810
2016		186,098
2017		29,862
	$	492,653

Capital leases

The Company entered into a lease for certain office furniture and equipment in the first quarter of 2014. The term of the lease is three years and as the lease essentially transfer the risks of ownership it is being accounted for as a capital lease.

Leased property under capital leases at June 30, 2014 includes:

	June 30, 2014
Furniture and equipment	$	127,436
less: accumulated depreciation		(8,496	)
	$	118,940

F-11

Total depreciation expense under capital leases was $6,372 and $8,496 for the three and six months ended June 30, 2014 and as of that date the future minimum lease payments under capital leases were as follows:

Year	Amount

2014 (July - December)	$	21,478
2015		42,956
2016		42,956
2017		7,158
		114,548
Less amount representing interest		(1,135	)
Present value of minimum lease payments	$	113,413

Current maturities	$	42,272
Non-current maturities		71,141
	$	113,413

Legal Proceedings

The Company is not a party to any litigation that has arisen in the normal course of its business or that of its subsidiaries.

Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. In 2010, the Company was notified by DIAN that it owed $883,742 in equity taxes relating to the 2001 and 2003 equity tax years. To compute the value the equity tax is assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001 and 2003. However, DIAN’s position is that as long as the field is productive, Cimarrona should not have subtracted the cost of the non-producing wells. In May 2011, we settled in full the 2001 equity liability with DIAN. In January 2012, we were informed by DIAN that we had lost our appeal on the 2003 tax issue and we increased the amount attributable to the 2003 tax year by $322,288 as of December 31, 2011 to correspond to the amount DIAN indicated we owed for the 2003 tax year. In January 2013, we successfully concluded negotiations with DIAN with respect to the ultimate liability for the 2003 tax year. DIAN waived certain interest and penalties. We paid the agreed final liability to DIAN in January 2013, and financed the payment with an unsecured Colombian term loan facility in the amount of $367,521. We recognized in discontinued operations the $531,644 benefit of the amnesty in the quarter ended June 30, 2013, upon receipt of official confirmation that the liability is fully settled. We repaid the unsecured Colombian term loan facility in October 2013 in conjunction with the sale of Cimarrona.

SALE OF CIMARRONA LLC

On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company, LLC (“Raven”), pursuant to a Membership Interest Purchase Agreement dated September 30, 2013 (the “Agreement”) by and between the Company and Raven. The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby Ecopetrol S.A. (“Ecopetrol”) receives royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association Contract have received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. If such an audit determines that the specified reimbursement of historical costs occurred prior to September 30, 2013, the Company is required to reimburse Raven for any amounts due to Ecopetrol from Cimarrona LLC which relate to the period prior to that date. The Company believes its maximum exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013, or $729,308. The Company has not recorded any provision for this matter, as it is not possible to estimate the potential liability, if any.

F-12

8. MAJOR CUSTOMERS

During the three and six months ended June 30, 2014 and 2013, the Company had the following customers who accounted for all of its sales:

	Three Months ended					Three Months ended
	June 30, 2014					June 30, 2013
	Amount		% of Total			Amount		% of Total
Slawson	$	1,638,250		66.1	%	$	966,213		73.3	%
Devon		492,857		19.9	%		102,516		7.8	%
Stephens		161,627		6.5	%		235,251		17.9	%
CMO Energy Partners		153,698		6.2	%		-		-
Phillips 66		16,690		0.7	%		-		-
Sundance		15,574		0.6	%		13,613		1.0	%
Total	$	2,478,696		100.0	%	$	1,317,593		100.0	%

	Six Months ended					Six Months ended
	June 30, 2014					June 30, 2013
	Amount		% of Total			Amount		% of Total
Slawson	$	3,555,914		69.5	%	$	1,918,284		75.8	%
Devon		1,036,326		20.3	%		280,438		11.1	%
Stephens		333,391		6.5	%		317,130		12.6	%
CMO Energy Partners		153,698		3.0	%		-		-
Phillips 66		16,690		0.3	%		-		-
Sundance		20,092		0.4	%		13,613		0.5	%
Total	$	5,116,111		100.0	%	$	2,529,465		100.0	%

9. LIABILITY FOR ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability at discounted fair value for the future retirement of tangible long-lived assets and associated assets retirement cost associated with the petroleum and natural gas properties. The fair value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. The related accretion expense is recognized in the statements of operations. The provision will be revised for the effect of any changes to timing related to cash flow or undiscounted abandonment costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligations (“AROs”) to the extent that the liability exists on the balance sheet. Differences between the actual costs incurred and the fair value of the liability recorded are recognized in income in the period the actual costs are incurred. There are no legally restricted assets for the settlement of AROs. No income tax is applicable to the ARO as of June 30, 2014 and December 31, 2013, because the Company records a valuation allowance on deductible temporary differences due to the uncertainty of its realization.

A reconciliation of the Company’s asset retirement obligations for the six months ended June 30, 2014 is as follows:

	Six Months Ended
	June 30, 2014
Beginning balance	$	3,886
Incurred during the period		-
Reversed during the period		-
Additions for new wells		243
Accretion expense		412
Ending balance	$	4,541

F-13

10. EQUITY

Common Stock

In February 2014, the Company initiated a private placement, pursuant to Securities Purchase Agreements between Osage and certain purchasers, with aggregate gross proceeds of approximately $6.7 million. The purchase price of each unit, representing one share of common stock and a warrant to purchase 0.4 shares of common stock at $1.80 per share, was $0.90. The warrants have a term of five years. The placement agent received placement fees of 8%, in cash or warrants or a combination thereof at their election. As of June 30, 2014 units representing $6,744,000 had been sold, representing 7,493,333 shares of common stock and warrants to purchase 2,997,333 shares of common stock. The placement agent fees related to these units as of June 30, 2014 were cash fees of $427,100 and warrants to purchase 196,620 shares of common stock at $0.01 per share. In addition, the Company incurred legal fees of $10,000 with respect to the private placement.

On January 2, 2014 we issued a total of 550,000 shares to three individuals in connection with amended employment and consulting agreements. Stock based compensation had already been expensed for 150,000 shares as discussed below. The remaining 400,000 shares vest on January 1, 2015, were valued at $436,000 based on closing prices of $1.00 for 200,000 shares and $1.18 for 200,000 shares and are being expensed over one year.

On June 5, 2014 we issued a total of 600,000 non-qualified stock options to two employees and a consultant, exercisable at $0.8925 per share, with a Black-Scholes value of $629,714 and an expiration date of June 4, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 10 years, (3) expected volatility of 220.0% and 219.0% for employees and consultant, respectively, and (4) zero expected dividends. These options were fully vested as of the grant date.

During the three months ended March 31, 2013 we issued 400,000 shares which vested immediately to two employees with a fair value of $364,000, or $0.91 per share. On August 1, 2012, in connection with a three-year employment agreement, we agreed to issue 150,000 shares of common stock at future dates as specified in the agreement. The 150,000 shares were valued at $177,000, or $1.18 per share, and were being expensed over the three years of the employment agreement. We recognized $14,750 of expense related to these shares in the three months ended March 31, 2013. On January 2, 2014, we amended the employment agreement and the vesting of these shares accelerated, and we recognized the unamortized portion of the stock based compensation expense in the fourth quarter of 2013.

Warrants

During the three months ended March 31, 2014, 200,000 warrants were exercised by a consultant who had previously received the warrants in exchange for services.

On April 10, 2014 we issued a warrant to purchase 2,000,000 shares of common stock to a consultant, exercisable at $1.04 per share, with a Black-Scholes value of $2,184,538 and an expiration date of April 9, 2017. Variables used in the valuation include (1) discount rate of 0.81%, (2) expected life of 3 years, (3) expected volatility of 223.0% and (4) zero expected dividends. This warrant was fully vested as of the grant date.

Total stock-based compensation expense was $2,923,252 and $26,750 for the three months ended June 30, 2014 and 2013, respectively, and $3,032,252 and $405,500 for the six months ended June 30, 2014 and 2013, respectively.All stock-based compensation expense is included in general and administrative expenses in the accompanying unaudited financial statements.

11. DISCONTINUED OPERATIONS

On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven, pursuant to the Agreement dated September 30, 2013 by and between the Company and Raven. Cimarrona LLC is the owner of a 9.4% interest in certain oil and gas assets including a pipeline in the Guaduas field, located in the Dindal and Rio Seco Blocks that covers 30,665 acres in the Middle Magdalena Valley in Colombia.

The sales price consisted of cash of $6,800,000, less settlement of debt of Cimarrona LLC of approximately $250,000. Of the net sales price, $250,000 will be held in escrow for 12 months to secure any post-Closing purchase price adjustments and any indemnity obligations of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with respect to the pipeline is not adjusted prior to March 31, 2014, then Raven is obligated to pay the Company an additional $1,000,000 in cash. Pursuant to the Agreement, the Company also recognized a receivable for a working capital adjustment of $422,955 in other current assets as of December 31, 2013 and recognized a gain on disposal of discontinued operations of $4,873,660 in the year ended December 31, 2013. Raven has reimbursed the Company for the working capital adjustment. The Company and Raven are in discussions about the status of the per barrel transportation rate with respect to the pipeline, and the Company does not presently have sufficient information to estimate the outcome of these discussions.

F-14

The following table sets forth the results of operations for the discontinued operations for the three and six months ended June 30, 2013:

	Three Months			Six Months
	ended			ended
	June 30, 2013			June 30, 2013
Revenues
Oil revenues	$	460,749		$	1,076,436
Pipeline revenues		611,919			1,211,111
Total revenues		1,072,668			2,287,547

Operating costs and expenses
Operating expenses		362,590			679,128
Depreciation, depletion and accretion		45,866			104,618
Equity tax		(499,922	)		(466,958	)
General and administrative		26,374			48,164
Total operating costs and expenses		(65,092	)		364,952

Operating income		1,137,760			1,922,595

Other income (expenses):
Interest income		13			84
Interest expense		(9,208	)		(16,456	)
Income before income taxes		1,128,565			1,906,223
Provision for income taxes		-			-
Net income	$	1,128,565		$	1,906,223

F-15

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 that include, among others, statements of: expectations, anticipations, beliefs, estimations, projections, and other similar matters that are not historical facts, including such matters as: future capital requirements, development and exploration expenditures (including the amount and nature thereof), drilling of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and gas, repayment of debt, business strategies, and expansion and growth of business operations. These statements are based on certain assumptions and analyses made by our management in light of past experience and perception of: historical trends, current conditions, expected future developments, and other factors that our management believes are appropriate under the circumstances. We caution the reader that these forward-looking statements are subject to risks and uncertainties, including those associated with the financial environment, the regulatory environment, and trend projections, that could cause actual events or results to differ materially from those expressed or implied by the statements. Such risks and uncertainties include those risks and uncertainties identified below. Significant factors that could prevent us from achieving our stated goals include: declines in the market prices for oil and gas, adverse changes in the regulatory environment affecting us, the inherent risks involved in the evaluation of properties targeted for acquisition, our dependence on key personnel, the availability of capital resources at terms acceptable to us, the uncertainty of estimates of proved reserves and future net cash flows, the risk and related cost of replacing produced reserves, the high risk in exploratory drilling and competition. You should consider the cautionary statements contained or referred to in this report in connection with any subsequent written or oral forward-looking statements that may be issued. We undertake no obligation to release publicly any revisions to any forward-looking statement to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

On April 8, 2008, we entered into a membership interest purchase agreement (the “Purchase Agreement”) with Sunstone Corporation (“Sunstone”) pursuant to which we acquired from Sunstone 100% of the membership interests in Cimarrona Limited Liability Company, an Oklahoma limited liability company (“Cimarrona LLC”). Cimarrona LLC owns a 9.4% interest in certain oil and gas assets in the Guaduas field, located in the Dindal and Rio Seco Blocks that consist of 21 wells, of which seven are currently producing, that covers 30,665 acres in the Middle Magdalena Valley in Colombia as well as a pipeline with a current capacity of approximately 40,000 barrels of oil per day. The Purchase Agreement was effective as of April 1, 2008. The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby we pay Ecopetrol S.A. (“Ecopetrol”) royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. The royalty amount for the Cimarrona property is paid in oil. The property and the pipeline are both operated by Pacific, which owns 90.6% of the Guaduas field. Pipeline revenues generated from the Cimarrona property primarily relate to transportation costs charged to third party oil producers, including Pacific.

On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company, LLC (“Raven”), pursuant to a Membership Interest Purchase Agreement (the “Agreement”) dated September 30, 2013 by and between the Company and Raven. Accordingly, the Company will not recognize any revenues or expenses for Cimarrona LLC from October 1, 2013. The sales price consisted of cash of $6,800,000, less settlement of debt of Cimarrona LLC of approximately $250,000. Of the net sales price, $250,000 will be held in escrow for 12 months to secure any post-closing purchase price adjustments and any indemnity obligations of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with respect to the pipeline is not adjusted prior to June 30, 2014, then Raven is obligated to pay the Company an additional $1,000,000 in cash within five business days of that date. The Company and Raven are in discussions about the per barrel transportation rate, and the Company does not presently have sufficient information to estimate the outcome.

In 2010, we began to acquire oil and gas leases in Logan County, Oklahoma targeting the Mississippian formation. The Mississippian formation is located on the Anadarko Shelf in northern Oklahoma and south-central Kansas. The top of this expansive carbonate hydrocarbon system is encountered between 4,000 and 6,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow Sand and the Devonian-aged Woodford Shale formations. The Mississippian formation may reach 600 feet in gross thickness and the targeted porosity zone is between 50 and 300 feet in thickness. The formation’s geology is well understood as a result of the thousands of vertical wells drilled and produced there since the 1940s. Beginning in 2007, the application of horizontal cased-hole drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation.

On April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE,” Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, Oklahoma for $4,875,000. In addition, the Parties carried Osage for 7.5% of the cost of the first three horizontal Mississippian wells, which means that for the first three horizontal Mississippian wells, the Company provided up to 17.5% of the total well costs. After the first three wells, the Company was responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty payments, was allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson was the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’ acreage controlled the section. In sections where the Parties’ acreage did not control the section, we may elect to participate in wells operated by others.

On December 12, 2013, Osage and Slawson entered into an agreement (the “Partition Agreement”) which amended Participation Agreement related to certain lands located within the Nemaha Ridge in Logan County, Oklahoma, and for the exploration and development of those leases by the Parties.

Under the Partition Agreement and effective as of September 1, 2013, the Slawson Exploration Group agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to the Slawson Exploration Group, such that the net acreage controlled by the parties would remain substantially unchanged, but that the acreage controlled by each of the parties in undeveloped sections would be located in sections where the other party did not control acreage. The parties also agreed that the Participation Agreement would terminate as to all lands within the Nemaha Ridge Project except for lands within sections already developed by the parties which shall continue to be controlled by the Participation Agreement.

In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. The Wood ford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At June 30, 2014, we had 4,246 net (9,509 gross) acres leased in Coal County.

At June 30, 2014, we have leased 17,804 net (50,983 gross) acres across three counties in Oklahoma as follows:

	Gross		Osage Net
Logan (non operated)		30,088		5,185
Logan - Osage		6,301		4,183
Coal		9,509		4,246
Pawnee		5,085		4,190
		50,983		17,804

We have accumulated deficits of $9,552,356 (unaudited) at June 30, 2014 and $4,219,480 at December 31, 2013. Substantial portions of the losses are attributable to stock-based compensation, professional fees and interest expense.

Management of the Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond. These steps include (a) becoming and operator of our own wells, (b) participating in drilling of wells in Logan County, Oklahoma, (c) controlling overhead and expenses, and (d) raising additional equity and/or debt.

On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation. On April 5, 2013 we amended this agreement, increasing the facility to $20,000,000 and on April 3, 2014 we further amended this agreement, increasing the facility to $30,000,000, extending the term of the facility by one year, reducing the interest rate from Libor plus 15% to Libor plus 11% and agreeing to modify the covenants to reflect the transition from participant to operator. On April 7, 2014, we drew down an additional $5 million, bringing total borrowings under the Note Purchase Agreement to $25 million.

The Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s ability to continue as a going concern is in substantial doubt and is dependent upon achieving profitable operations and obtaining additional financing. There is no assurance additional funds will be available on acceptable terms or at all. In the event we are unable to continue as a going concern, we may elect or be required to seek protection from our creditors by filing a voluntary petition in bankruptcy or may be subject to an involuntary petition in bankruptcy.

Results of Operations

Three Months ended June 30, 2014 compared to Three Months ended June 30, 2013

Our total revenues for the three months ended June 30, 2014 and 2013 comprised the following:

	2014					2013					Change
	Amount		Percentage			Amount		Percentage			Amount		Percentage
Revenues
Oil sales	$	1,895,201		76.5	%	$	1,220,811		92.7	%	$	674,390		55.2	%
Natural gas sales		583,495		23.5	%		96,782		7.3	%		486,713		502.9	%
Total revenues	$	2,478,696		100.0	%	$	1,317,593		100.0	%	$	1,161,103		88.1	%

Oil Sales

Oil Sales were $1,895,201, an increase of $674,390, or 55.2%, for the three months ended June 30, 2014 compared to $1,220,811 for the three months ended June 30, 2013. Oil sales increased due to an increase in the number of barrels sold and an increase in the average price per barrel. We sold 17,591 barrels (“BBLs”) at an average price of $102.56 in the 2014 period, compared to 13,264 BBLs at an average price of $91.64 in the 2013 period. We began well production in Logan County, Oklahoma, in the first quarter of 2012, and continue to develop wells in that area, which accounted for the increase in oil sales.

Natural Gas Sales

Natural gas sales comprise revenues from the sale of natural gas and natural gas liquids. Natural gas sales were $446,417 for the three months ended June 30, 2014 compared to $79,950 for the three months ended June 30, 2013, an increase of $366,467, or 458.4%. Natural gas liquid sales were $137,078 for the three months ended June 30, 2014 compared to $16,832 in the three months ended June, 2013, and increase of $120,246 or 714.4%. All of our natural gas and natural gas liquid sales are from the well production in Logan County, Oklahoma.

Total revenues were $2,478,696 an increase of $1,161,103, or 88.1% for the three months ended June 30, 2014 compared to $1,137,593 for the three months ended June 30, 2013. Oil sales accounted for 76.5% and 92.7% of total revenues in the 2014 and 2013 periods, respectively.

Production

For the three months ended June 30, 2014 and 2013, our production was as follows:

	2014				2013				Increase/(Decrease)
Oil Production:		Net Barrels	% of Total			Net Barrels	% of Total			Barrels	%
United States		17,918	100.0	%		13,568	100.0	%		4,350	32.1	%

Natural Gas Production:		Net Mcf	% of Total			Net Mcf	% of Total			Mcf	%
United States		96,410	100.0	%		19,076	100.0	%		77,334	405.4	%

Natural Gas Liquid Production:		Net Barrels	% of Total			Net Barrels	% of Total			Barrels	%
United States		4,770	100.0	%		647	100.0	%		4,123	637.2	%

Oil production, net of royalties, was 17,918 BBLs, an increase of 4,350 BBLs, or 32.1% for the three months ended June 30, 2014 compared to 13,568 BBLs for the three months ended June 30, 2013, due to production increases as a result of new wells coming online.

Natural gas production was 96,410 thousand cubic feet (“Mcf”) for the three months ended June 30, 2014, an increase of 77,334 Mcf, or 405.4% over the production of 19,076 Mcf in the 2013 period. Natural gas liquid production was 4,770 BBLs in the three months ended June 30, 2014 an increase of 4,123 BBLs or 637.2% over the production of 647 in the 2013 period. Gas production began in the first quarter of 2012 in our Logan County properties. We commenced production of natural gas liquids in the second quarter of 2013 at certain wells in Logan County.

Operating Costs and Expenses

For the three months ended June 30, 2014 and 2013, our operating costs and expenses were as follows:

	2014						2013					Change
				Percent of					Percent of
	Amount			Sales			Amount		Sales			Amount			Percentage
Operating costs and expenses
Operating expenses	$	390,699			15.8	%	$	356,489		27.1	%	$	34,210			9.6	%
General & administrative expenses		3,643,408			147.0	%		549,133		41.7	%		3,094,275			563.5	%
Depreciation, depletion and accretion		1,346,123			54.3	%		344,527		26.1	%		1,001,596			290.7	%
Total operating expenses	$	5,380,230			217.1	%	$	1,250,149		94.9	%	$	4,130,081			330.4	%

Operating (loss) income	$	(2,901,534	)		-117.1	%	$	67,444		5.1	%	$	(2,968,978	)		n/a

Operating Costs

Our operating costs were $390,699 for the three months ended June 30, 2014 compared to $356,489 for the three months ended June 30, 2013, due to an increase in operating costs in the U.S. as a result of having 44 wells in production in Logan County at June 30, 2014. Operating costs as a percentage of total revenues decreased to 15.8% in the 2014 period from 27.1% in 2013 period, as the percentage increase in revenues was greater than the percentage increase in operating costs as new wells came into production. The average production cost per barrel of oil equivalent (“Production Cost/BOE”) for the three months ended June 30, 2014 was $10.08 compared to an average total Production Cost/BOE of $20.55 for the three months ended June 30, 2013.

General and Administrative Expenses

General and administrative expenses were $3,643,408 for the three months ended June 30, 2014, compared to $549,133 for the three months ended June 30, 2013. As a percent of total revenues, general and administrative expenses increased to 147.0% in the 2014 period from 41.7% in the 2013 period. Stock based compensation for the three months ended June 30, 2014 was $2,923,252, compared to $26,750 in the three months ended June 30, 2013. Excluding stock based compensation, general and administrative expenses were $720,156, or 29.1% of revenues in the three months ended June 30, 2014, compared to $522,383, or 39.6% of revenues in the 2013 period. The increase of $197,773 in other general and administrative expenses was primarily due to increased salary, legal and professional and insurance expenses.

Depreciation, Depletion and Accretion

Depreciation, depletion and accretion were $1,346,123 for the three months ended June 30, 2014 and $344,527 for the three months ended June 30, 2014, an increase of $1,001,596 or 290.7%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.

Operating Income (Loss)

Operating loss was $2,901,534 for the three months ended June 30, 2014 compared to an operating income of $67,444 for the three months ended June 30, 2014. The decline in operating income to an operating loss is as a result of the increase in total operating expenses of 330.4% exceeding the 88.1% revenue growth.

Interest Expense

Interest expense was $1,215,579 for the three months ended June 30, 2014 compared to $1,129,640 for the three months ended June 30, 2013, an increase of $85,939. The increase in interest expense during the 2014 period was primarily due greater amounts outstanding under our credit facilities offset by a reduction in our weighted average cost of debt and a reduction in deferred financing fees as a result of the one year extension in the term of our Note Purchase Agreement. In the three months ended June 30, 2014, cash interest expense amounted to $1,025,080. The remaining non-cash interest expense of $190,499 represented amortization of deferred financing fees. In the three months ended June, 2013, cash interest expense amounted to $754,528. The remaining non-cash interest expense of $375,112 consisted primarily of deferred financing fees of $326,962 and debt discount amortization of $48,150.

Oil and Gas Derivatives

Oil and gas derivatives reflected an unrealized loss of $243,423 for the three months ended June 30, 2014 as a result of marking open financial derivative instruments to market as of June 30, 2014 and losses realized on financial derivative instruments settled of $119,572 during the three months then ended. For the three months ended June 30, 2013 oil and gas derivatives reflected only an unrealized loss of $36,690 as a result of marking open financial derivative instruments to market as of June 30, 2013.

Provision for Income Taxes

Provision for income taxes was zero for the three months ended June 30, 2014 and 2013. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its U.S. operations for the current period.

Loss from Continuing Operations

Loss from continuing operations was $4,397,749 for the three months ended June 30, 2014 compared to a loss of $1,097,863 for the three months ended June 30, 2013. The $2,968,978 decrease in operating income to an operating loss and the $326,305 increase in loss on oil and gas derivatives in the three months ended June 30, 2014 compared to the prior year period were the primary contributors.

Income from Discontinued Operations Net of Income Taxes

Income from discontinued operations net of income taxes was $1,128,565 in the three months ended June, 2013. These operations were disposed of effective September 30, 2013.

Net Income (Loss)

Net loss was $4,397,749 in the three months ended June 30, 2014 compared to a net income of $30,702 in 2013. The increase in loss from continuing operations of $3,299,886 and the reduction of $1,128,565 in net income from discontinued operations represent the drivers of the $4,428,451 increase in net loss.

Foreign Currency Translation Adjustment Attributable to Discontinued Operations

There was no foreign currency gain or loss in the three months ended June 30, 2014 compared to a loss of $849 in 2013.

Comprehensive Income (Loss)

Comprehensive loss was $4,397,749 for the three months ended June 30, 2014 compared to comprehensive income of $29,853 for the three months ended June, 2013. The increase in net loss was the primary contributor.

Income (Loss) per Share

Basic and diluted loss per share from continuing operations was $0.08 the three months ended June 30, 2014 compared to a loss per share of $0.02 in the prior year period. There was no income from discontinued operations in the three months ended June 30, 2014, compared to basic and diluted income from discontinued of $0.02 per share in the prior year period.

Six Months ended June 30, 2014 compared to Six Months ended June 30, 2013

Our total revenues for the six months ended June 30, 2014 and 2013 comprised the following:

	2014					2013					Change
	Amount		Percentage			Amount		Percentage			Amount		Percentage
Revenues
Oil sales	$	4,028,018		78.7	%	$	2,308,650		91.3	%	$	1,719,368		74.5	%
Natural gas sales		1,088,093		21.3	%		220,815		8.7	%		867,278		392.8	%
Total revenues	$	5,116,111		100.0	%	$	2,529,465		100.0	%	$	2,586,646		102.3	%

Oil Sales

Oil Sales were $4,028,018, an increase of $1,719,368, or 74.5%, for the six months ended June 30, 2014 compared to $2,308,650 for the six months ended June 30, 2013. Oil sales increased due to an increase in the number of barrels sold and an increase in the average price per barrel. We sold 39,018 barrels (“BBLs”) at an average price of $99.43 in the 2014 period, compared to 25,149 BBLs at an average price of $92.04 in the 2013 period. We began well production in Logan County, Oklahoma, in the first quarter of 2012, and continue to develop wells in that area, which accounted for the increase in oil sales.

Natural Gas Sales

Natural gas sales comprise revenues from the sale of natural gas and natural gas liquids. Natural gas sales were $898,201 for the six months ended June 30, 2014 compared to $203,983 for the six months ended June 30, 2013, an increase of $694,218, or 340.3%. Natural gas liquid sales were $189,892 for the six months ended June 30, 2014 compared to $16,832 in the prior year, and increase of $173,060 or 1,028.2%. All of our natural gas and natural gas liquid sales are from the well production in Logan County, Oklahoma.

Total revenues were $5,116,111, an increase of $2,586,646, or 102.3% for the six months ended June 30, 2014 compared to $2,529,465 for the six months ended June 30, 2013. Oil sales accounted for 78.7% and 91.3% of total revenues in the 2014 and 2013 periods, respectively.

Production

For the six months ended June 30, 2014 and 2013, our production was as follows:

	2014				2013				Increase/(Decrease)
Oil Production:		Net Barrels	% of Total			Net Barrels	% of Total			Barrels	%
United States		40,248	100.0	%		25,746	100.0	%		14,502	56.3	%

Natural Gas Production:		Net Mcf	% of Total			Net Mcf	% of Total			Mcf	%
United States		174,037	100.0	%		45,664	100.0	%		128,373	281.1	%

Natural Gas Liquid Production:		Net Barrels	% of Total			Net Barrels	% of Total			Barrels	%
United States		6,566	100.0	%		647	100.0	%		5,919	914.8	%

Oil production, net of royalties, was 40,248 BBLs, an increase of 14,502 BBLs, or 56.3% for the six months ended June 30, 2014 compared to 25,746 BBLs for the six months ended June 30, 2013, due to production increases as a result of new wells coming online.

Natural gas production was 174,037 Mcf for the six months ended June 30, 2014, an increase of 128,373 Mcf, or 281.1% over the production of 45,664 Mcf in the 2013 period. Natural gas liquid production was 6,566 BBLs in the six months ended June 30, 2014, an increase of 5,919 BBLs or 914.8% over the production of 647 BBLs in the 2013 period. Gas production began in the first quarter of 2012 in our Logan County properties. We commenced production of natural gas liquids in the second quarter of 2013 at certain wells in Logan County.

Operating Costs and Expenses

For the six months ended June 30, 2014 and 2013, our operating costs and expenses were as follows:

	2014						2013						Change
				Percent of						Percent of
	Amount			Sales			Amount			Sales			Amount			Percentage
Operating costs and expenses
Operating expenses	$	863,841			16.9	%	$	538,860			21.3	%	$	324,981			60.3	%
General & administrative expenses		4,487,360			87.7	%		1,392,843			55.1	%		3,094,517			222.2	%
Depreciation, depletion and accretion		2,346,022			45.9	%		615,012			24.3	%		1,731,010			281.5	%
Total operating expenses	$	7,697,223			150.5	%	$	2,546,715			100.7	%	$	5,150,508			202.2	%

Operating loss	$	(2,581,112	)		-50.5	%	$	(17,250	)		-0.7	%	$	(2,563,862	)		14863.0	%

Operating Costs

Our operating costs were $863,841 for the six months ended June 30, 2014 compared to $538,860 for the six months ended June 30, 2013, due to an increase in operating costs in the U.S. as a result of having 44 wells in production in Logan County at June 30, 2014. Operating costs as a percentage of total revenues decreased to 16.9% in the 2014 period from 21.3% in 2013 period, as the percentage increase in revenues was greater than the percentage increase in operating costs as new wells came into production. The average Production Cost/BOE for the six months ended June 30, 2014 was $11.39 compared to an average total Production Cost/BOE of $15.89 for the six months ended June 30, 2013.

General and Administrative Expenses

General and administrative expenses were $4,487,360 for the six months ended June 30, 2014, compared to $1,392,843 for the six months ended June 30, 2013, an increase of $3,094,517, or 222.2%. As a percent of total revenues, general and administrative expenses increased to 87.7% in the 2014 period from 55.1% in the 2013 period. Stock based compensation for the six months ended June 30, 2014 was $3,032,252, compared to $405,500 in the six months ended June 30, 2013. The increase of $467,765 in other general and administrative expenses was primarily due to increased salary, legal and professional and insurance expenses.

Depreciation, Depletion and Accretion

Depreciation, depletion and accretion were $2,346,022 for the six months ended June 30, 2014 and $615,012 for the six months ended June 30, 2013, an increase of $1,731,010 or 281.5%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.

Operating Income (Loss)

Operating loss was $2,581,112 for the six months ended June 30, 2014 compared to an operating loss of $17,250 for the six months ended June 30, 2013. The increase in operating loss is as a result of the increase in operating costs and expenses of 202.2% exceeding the 102.3% revenue growth.

Interest Expense

Interest expense was $2,426,139 for the six months ended June 30, 2014 compared to $1,896,146 for the six months ended June 30, 2013, an increase of $529,993. The increase in interest expense during the 2014 period was primarily due to greater amounts outstanding under our credit facilities offset by a reduction in our weighted average cost of debt and a reduction in deferred financing fees as a result of the one year extension in the term of our Note Purchase Agreement. In the six months ended June 30, 2014, cash interest expense amounted to $1,887,657. The remaining non-cash interest expense of $538,482 represented amortization of deferred financing fees. In the six months ended June 30, 2013, cash interest expense amounted to $1,163,307. The remaining non-cash interest expense of $732,839 consisted primarily of deferred financing fees of $641,424 and debt discount amortization of $91,415.

Oil and Gas Derivatives

Oil and gas derivatives reflected an unrealized loss of $311,480 for the six months ended June 30, 2014 as a result of marking open financial derivative instruments to market as of June 30, 2014 and losses realized on financial derivative instruments settled of $167,242 during the six months then ended. For the six months ended June 30, 2013 oil and gas derivatives reflected only an unrealized loss of $36,690 as a result of marking open financial derivative instruments to market as of June 30, 2013.

Provision for Income Taxes

Provision for income taxes was zero for the six months ended June 30, 2014 and 2013. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its U.S. operations for the current period.

Loss from Continuing Operations

Loss from continuing operations was $5,332,876 for the six months ended June 30, 2014 compared to a loss of $1,948,946 for the six months ended June 30, 2013. The primary contributors were the $2,563,862 increase in operating loss, the $529,993 increase in interest expense and the $442,032 increase in losses on oil and gas derivatives.

Income from Discontinued Operations Net of Income Taxes

Income from discontinued operations net of income taxes was $1,906,223 in the six months ended June 30, 2013. These operations were disposed of effective September 30, 2013.

Net Income (Loss)

Net loss was $5,332,876 in the six months ended June 30, 2014 compared to a net loss of $42,723 in 2013. The increase in loss from continuing operations of $3,383,930 and the reduction of $1,906,223 in net income from discontinued operations represent the drivers of the $5,290,153 increase in net loss.

Foreign Currency Translation Adjustment Attributable to Discontinued Operations

There was no foreign currency gain or loss in the six months ended June 30, 2014 compared to a gain of $22,714 in 2013.

Comprehensive Income (Loss)

Comprehensive loss was $5,332,876 for the six months ended June 30, 2014 compared to a comprehensive loss of $20,009 for the six months ended June 30, 2013. The $5,290,153 increase in net loss to $5,332,876 in 2014 was the primary contributor, partially offset by the foreign currency translation gain of $22,714 in the prior year period.

Income (Loss) per Share

Basic and diluted loss per share from continuing operations was $0.10 for the six months ended June 30, 2014 compared to a loss per share of $0.04 in the prior year period. There was no income from discontinued operations in the six months ended June 30, 2014, compared to basic and diluted income from discontinued operations of $0.04 per share in the prior year period.

Liquidity and Capital Resources

Net cash provided by operating activities totaled $5,088,031 for the six months ended June 30, 2014, compared to net cash used of $502,191 for the six months ended June, 2013. The major components of net cash provided by operating activities for the six months ended June 30, 2014 included non-cash activities which consisted of stock based compensation of $3,032,252, provision for depreciation, depletion and accretion of $2,345,610, amortization of deferred financing costs of $538,482 and unrealized losses on derivative contracts of $311,480. Other significant components included the $2,629,212 increase in joint interest billing account, partially offset by a decrease in accounts receivable of $868,372 and by the net loss of $5,332,876. The major components of net cash used by operating activities for the six months ended June 30, 2013 included non-cash activities which consisted of stock based compensation of $405,500, provision for depreciation, depletion and accretion of $714,899, amortization of deferred financing costs of $641,424 and amortization of debt discount of $91,415. Other components included the $132,154 increase in accounts payable due primarily to our Oklahoma operations related to well production and partially offset by a decrease of $907,619 in accrued expenses and an increase in accounts receivable of $1,612,442.

Net cash used in investing activities totaled $8,784,106 for the six months ended June 30, 2014 and consisted primarily of investments in oil and gas properties of $9,115,107 as the Company began drilling and operating its own wells in Logan County, Oklahoma, partially offset by net proceeds from the sale of oil and gas properties of $339,165. Net cash used in investing activities totaled $10,049,782 for the six months ended June 30, 2013 and consisted primarily of investments in oil and gas wells of $9,957,828.

Net cash provided by financing activities totaled $11,194,878 for the six months ended June 30, 2014 and consisted primarily of $6,306,900 in net proceeds from a private placement of securities and $5,000,000 proceeds from the Note Purchase Agreement. Net cash provided by financing activities amounted to $10,178,873 in the six months ended June 30, 2013, consisting primarily of $10,000,000 proceeds from the Note Purchase Agreement.

Our capital expenditures are directly related to drilling operations and the completion of successful wells. Our level of expenditures in the U.S. is dependent upon successful operations and availability of financing.

Effect of Changes in Prices

Changes in prices during the past few years have been a significant factor in the oil and gas (“O&G”) industry. The price received for the oil produced by us fluctuated significantly during the last year. Changes in the price received for our O&G is set by market forces beyond our control as well as governmental intervention. The volatility and uncertainty in O&G prices have made it more difficult for a company like us to increase our O&G asset base and become a significant participant in the O&G industry. We currently sell all of our O&G production to Slawson, Devon, Stephens, CMO Energy Partners, Phillips 66 and Sundance in the U.S. However, in the event these customers discontinued O&G purchases, we believe we can replace these customers with other customers who would purchase the oil at terms standard in the industry. In our Logan county properties, we sold oil and gas at prices ranging from $93.80 to $104.90 per barrel and $3.81 to $6.89 per Mcf in the six months ended June 30, 2014 and at prices ranging from $90.28 to $94.27 per barrel and $3.81 to $6.61 per Mcf in the six months ended June 30, 2013. We began to sell natural gas liquids in the second quarter of 2013 and we sold natural gas liquids in our Logan county properties at prices ranging from $27.00 to $35.33 per barrel in the six months ended June 30, 2014 and 25.91 to 28.87 per barrel in the prior year.

We have exposure to changes in interest rates as our Apollo debt facility is tied to the London inter-bank overnight rate.

Oil and Gas Properties

We follow the “successful efforts” method of accounting for our O&G exploration and development activities, as set forth in FASB ASC Topic 932 (“ASC 932”). Under this method, we initially capitalize expenditures for O&G property acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful. The carrying value of all undeveloped O&G properties is evaluated periodically and reduced if such carrying value appears to have been impaired. Leasehold costs relating to successful O&G properties remain capitalized while leasehold costs which have been proven unsuccessful are charged to operations in the period the leasehold costs are proven unsuccessful. Costs of carrying and retaining unproved properties are expensed as incurred. The costs of drilling and equipping development wells are capitalized, whether the wells are successful or unsuccessful. The costs of drilling and equipping exploratory wells are capitalized until they are determined to be either successful or unsuccessful. If the wells are successful, the costs of the wells remain capitalized. If, however, the wells are unsuccessful, the capitalized costs of drilling the wells, net of any salvage value, are expensed in the period the wells are determined to be unsuccessful. We did not record any impairment charges during the six months ended June 30, 2014 or 2013. The provision for depreciation and depletion of O&G properties is computed on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of O&G properties including future development, site restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of O&G produced during the period by the total estimated units of proved O&G reserves. This calculation is done on a field-by-field basis. As of June 30, 2014 and 2013 our oil production operations were conducted in the U.S. The cost of unevaluated properties not being amortized, to the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized cost. The cost of any impaired property is transferred to the balance of O&G properties being depleted. The costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which we intend to commence such activities in the future. We will begin to amortize these costs when proved reserves are established or impairment is determined. In accordance with FASB ASC Topic 410 (“ASC 410”), “Accounting for Asset Retirement Obligations,” we record a liability for any legal retirement obligations on our O&G properties. The asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate the producing properties at the end of their productive lives, in accordance with State laws, as well as the estimated costs associated with the reclamation of the property surrounding. The Company determines the asset retirement obligations by calculating the present value of estimated cash flows related to the liability. The asset retirement obligations are recorded as a liability at the estimated present value as of the asset’s inception, with an offsetting increase to producing properties. Periodic accretion of the discount related to the estimated liability is recorded as an expense in the statement of operations.

The estimated liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells, and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations. Revisions to the asset retirement obligations are recorded with an offsetting change to producing properties, resulting in prospective changes to depletion and depreciation expense and accretion of the discount. Because of the subjectivity of assumptions and the relatively long lives of most of the wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.

Revenue Recognition

We recognize revenue upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received by the customer, (ii) an invoice is generated which evidences an arrangement between the customer and us, (iii) a fixed sales price has been included in such invoice and (iv) collection from such customer is probable.

Off-Balance Sheet Arrangements

Our Company has not entered into any transaction, agreement or other contractual arrangement with an entity unconsolidated with us, except as disclosed in our financial statements, under which we have:

●	an obligation under a guarantee contract,

●	a retained or contingent interest in assets transferred to the unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets,

●	any obligation including a contingent obligation, under a contract that would be accounted for as a derivative instrument, or

●	any obligation, including a contingent obligation, arising out of a variable interest in an unconsolidated entity that is held by us and material to us where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with us.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Our Company is a Smaller Reporting Company. A Smaller Reporting Company is not required to provide the disclosure information required by this item.

Item 4. Controls and Procedures

The Company’s management, including its principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended, (the “Exchange Act”). Based upon their evaluation, the principal executive officer and principal financial offer concluded that, as of the end of the period covered by this report, the Company’s disclosure controls and procedures were not effective for the purpose of ensuring that the information required to be disclosed in the reports that the Company files or submits under the Exchange Act with the Securities and Exchange Commission (“SEC”) (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting (“ICFR”) as of March 31, 2014, utilizing a top-down, risk-based approach described in SEC Release No. 34-55929 as suitable for smaller public companies. Based on this assessment, management determined that the Company’s ICFR as of June 30, 2014 is not effective, and that, as of June 30, 2014, there were material weaknesses in our ICFR. The material weaknesses identified during management’s assessment was the lack of independent oversight by an audit committee of independent members of the Board of Directors. As defined by the Public Company Accounting Oversight Board Auditing Standard No. 5, a material weakness is a deficiency, or a combination of deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected. Given the difficulty of finding qualified individuals who are willing to serve as independent directors, there has been no change in the audit committee. Our internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that accurately and fairly reflect, in reasonable detail, transactions and dispositions of assets; and provide reasonable assurances that: (1) transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP; (2) receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and (3) unauthorized acquisitions, use, or disposition of the Company’s assets that could have a material effect on the Company’s financial statements are prevented or timely detected. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparations and presentations. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. This quarterly report does not include an attestation report of the Company’s independent registered public accounting firm regarding ICFR. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to rules of the SEC.

Except as indicated herein, there were no changes in the Company’s ICFR during the six months ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

We are not a party to, or the subject of, any material pending legal proceedings other than ordinary, routine litigation incidental to our business.

Item 1A. Risk Factors

Our Company is a Smaller Reporting Company. A Smaller Reporting Company is not required to provide the risk factor disclosure required by this item.

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

In January 2014, we issued a total of 550,000 shares to three individuals in connection with amended employment and consulting agreements.

In January 2014, 200,000 warrants were exercised by a consultant who had previously received the warrants in exchange for services.

In April 2014 we issued a warrant to purchase 2,000,000 shares of common stock to a consultant, exercisable at $1.04 per share.

In June 2014 we issued a total of 600,000 non-qualified stock options to two employees and a consultant, exercisable at $0.8925 per share.

The issuance of the securities of the Company in the above transactions was deemed to be exempt from registration under the Securities Act of 1933 by virtue of Section 4(2) thereof or Rule 506 of Regulation D promulgated there under, as transactions by an issuer not involving a public offering. With respect to the transactions listed above, no general solicitation was made by either the Company or any person acting on the Company’s behalf; the securities sold are subject to transfer restrictions; and the certificates for the shares contain an appropriate legend stating that such securities have not been registered under the Securities Act of 1933 and may not be offered or sold absent registration or pursuant to an exemption there from.

Item 3. Default upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable

Item 5. Other Information

(a) None.

(b) None.

Item 6. Exhibits

See Exhibit Index attached hereto.

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 of the undersigned thereunto duly authorized.

	OSAGE EXPLORATION AND DEVELOPMENT, INC.
	(Registrant)

Date: August 14, 2014	By:	/s/ Kim Bradford
		Kim Bradford
		President and Chief Executive Officer

Date: August 14, 2014	By:	/s/ Norman Dowling
		Norman Dowling
		Principal Financial Officer

EXHIBIT INDEX

The following is a list of Exhibits required by Item 601 of Regulation S-K. Except for these exhibits indicated by an asterisk which are filed herewith, the remaining exhibits below are incorporated by reference to the exhibit previously filed by us as indicated.

Exhibit No.		Description

3.1		Articles of Incorporation of Osage Exploration and Development, Inc. (1)

3.2		Bylaws of Osage Exploration and Development, Inc. (2)

31.1		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, signed by Kim Bradford, President and Chief Executive Officer (Principal Executive Officer)*

31.2		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, signed by Norman Dowling, Chief Financial Officer (Principal Financial Officer)*

32.1		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Kim Bradford, President and Chief Executive Officer (Principal Executive Officer)*

32.2		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Norman Dowling, Chief Financial Officer (Principal Financial Officer)*

101.INS		XBRL Instance Document*
101.SCH		XBRL Taxonomy Extension Schema*
101.CAL		XBRL Taxonomy Extension Calculation Linkbase*
101.DEF		XBRL Taxonomy Extension Definition Linkbase*
101.LAB		XBRL Taxonomy Extension Label Linkbase*
101.PRE		XBRL Taxonomy Presentation Linkbase*

	(1)	Incorporated herein by reference to Exhibit 3.1 to the Osage Exploration and Development, Inc. Form 10-SB Amendment No. 1 filed August 27, 2007

	(2)	Incorporated herein by reference to Exhibit 3.2 to the Osage Exploration and Development, Inc. Form 10-SB Amendment No. 1 filed August 27, 2007

		(*) Filed with this Form 10-Q

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

Osage Exploration & Development (OSGE) Inactive 10-Q2014 Q2 Quarterly report

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