Osage Exploration & Development (OSGE) 10-Q 2013 Q1 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 March 31, 2013

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

For the transition period from _____ to _____

OSAGE EXPLORATION AND DEVELOPMENT, INC.

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

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

2445 5thAvenue 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 May 10, 2013 was 49,844,675.

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets; March 31, 2013 (unaudited) and December 31, 2012	F-1
	Consolidated Statements of Operations and Other Comprehensive Income (Loss); Three Months ended March 31, 2013 (unaudited) and 2012 (unaudited)	F-2
	Consolidated Statements of Cash Flows; Three Months ended March 31, 2013 (unaudited) and 2012 (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	9
Item 4.	Controls and Procedures	9
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	10
Item 1A.	Risk Factors	10
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	10
Item 3	Default upon Senior Securities	10
Item 4	Mine Safety Disclosures	10
Item 5	Other Information	10
Item 6	Exhibits	10
Signatures		10

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED BALANCE SHEETS

As of March 31, 2013 (unaudited) and December 31, 2012

	2013			2012
ASSETS
Current assets:
Cash and equivalents	$	1,058,223		$	486,205
Accounts receivable		915,088			486,112
Prepaid expenses		41,505			83,090
Deferred financing costs		-			2,924,472
Total current assets		2,014,816			3,979,879
Property and equipment, at cost:
Oil and gas properties and equipment (successful efforts method)		17,352,390			11,753,334
Pipeline infrastructure and equipment		712,305			729,818
Other property & equipment		85,746			85,746
		18,150,441			12,568,898
Less: accumulated depletion, depreciation and amortization		(2,255,588	)		(1,980,197	)
		15,894,853			10,588,701
Deferred financing costs		2,610,010			-
Restricted cash		221,090			157,467
Note receivable		3,000			6,000
Total assets	$	20,743,769		$	14,732,047
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	2,149,308		$	236,977
Income taxes payable		58,093			58,093
Accrued expenses		718,991			1,328,652
Term loan, current portion		183,760			-
Notes payable		-			3,000,000
Total current liabilities		3,110,152			4,623,722
Term loan, net of current portion		153,133			-
Notes payable, net of $227,795 and $271,060 debt discount as of March 31, 2013 and December 31, 2012, respectively		9,272,205			2,228,940
Liability for asset retirement obligations		25			19
Total liabilities		12,535,515			6,852,681
Commitments and contingencies
Stockholders’ Equity:
Common stock,$0.0001 par value, 190,000,000 shares authorized; 49,494,675 and 49,094,675 shares issued and outstanding		4,949			4,909
Additional paid-in capital		16,750,015			16,371,305
Stock purchase notes receivable		(95,000	)		(95,000	)
Accumulated deficit		(8,148,211	)		(8,074,786	)
Accumulated other comprehensive loss - currency translation loss		(303,499	)		(327,062	)
Total stockholders’ equity		8,208,254			7,879,366
Total liabilities and stockholders’ equity	$	20,743,769		$	14,732,047

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

F-1

OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2013 and March 31, 2012 (unaudited)

	2013			2012
Operating revenues
Oil revenues	$	1,703,526		$	873,125
Pipeline revenues		599,192			469,891
Natural gas revenues		124,033			12,503
Total operating revenues		2,426,751			1,355,519
Operating costs and expenses
Operating costs		498,909			304,866
General and administrative expenses		865,500			438,429
Equity tax		32,964			32,802
Depreciation, depletion and accretion		329,237			123,630
Total operating costs and expenses		1,726,610			899,727
Operating income		700,141			455,792
Other income (expenses):
Interest income		188			840
Interest expense		(773,754	)		(606	)
Income (loss) before income taxes		(73,425	)		456,026
Provision for income taxes		-			-
Net (loss) income		(73,425	)		456,026
Other comprehensive income, net of tax:
Foreign currency translation adjustment		23,563			(3,664	)
Comprehensive (loss) income	$	(49,862	)	$	452,362
Basic and diluted (loss) income per share	$	(0.00	)	$	0.01
Weighted average number of common share and common share equivalents used to compute basic and diluted (loss) income per share		49,481,632			47,949,061

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

F-2

OSAGE EXPLORATION AND DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2013 and March 31, 2012 (unaudited)

	2013			2012
Cash flows from operating activities:
Net (loss) income	$	(73,425	)	$	456,026
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Shares issued for services		378,750			41,400
Amortization of deferred financing costs		314,462			-
Amortization of debt discount		43,265			-
Write off of expired mineral rights leases		11,250			-
Accretion of asset retirement obligation		1			606
Provision for depletion, depreciation, amortization and valuation allowance		329,237			123,630
Changes in operating assets and liabilities:
(Increase) in accounts receivable		(428,976	)		(340,001	)
Decrease (increase) in prepaid expenses		41,586			(71,422	)
(Decrease) in income tax payable		-			(800	)
Increase in accounts payable		1,912,332			202,583
Increase in asset retirement obligations		5			-
(Decrease) increase in accrued expenses		(609,665	)		147,152
Net cash provided by operating activities		1,918,822			559,174
Cash flows from investing activities:
Investments in oil & gas properties		(5,706,259	)		(2,689,623	)
Net proceeds from assignment of leases		16,846			977,556
(Increase) in restricted cash		(63,623	)		-
Proceeds from notes receivable		3,000			-
Net cash used by investing activities		(5,750,036	)		(1,712,067	)
Cash flows from financing activities:
Proceeds from secured promissory notes		4,000,000			-
Proceeds from term loan		367,521			-
Principal payments on term loan		(30,628	)		-
Payment of deferred financing costs		-			(100,000	)
Net cash provided (used) by financing activities		4,336,893			(100,000	)
Effect of exchange rate on cash and equivalents		66,339			27,455
Net increase (decrease) in cash and equivalents		572,018			(1,225,438	)
Cash and equivalents - beginning of period		486,205			1,904,023
Cash and equivalents - end of period	$	1,058,223		$	678,585
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payment for interest	$	416,026		$	-
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Increase in asset retirement obligation	$	5		$	-

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

F-3

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013 and 2012

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, gas and natural gas liquids. The Company’s production activities are located in the State of Oklahoma and the country of Colombia. 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 2012 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

We have working capital deficits of $1,095,336 (unaudited) at March 31, 2013 and $643,843 at December 31, 2012.

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) assigning a portion of our oil and gas leases in Logan County, Oklahoma, (b) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and expenses and (d) raising additional equity and/or debt.

On April 17, 2012, we issued a secured promissory note to Boothbay Royalty Co. for gross proceeds of $2,500,000. On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation and on April 5, 2013 we amended this agreement, increasing the facility to $20,000,000 (see Note 5 - 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 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.

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 unaudited 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 Cimarrona Limited Liability Company (“Cimarrona 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.

F-4

Reclassifications

Certain amounts included in the prior period financial statements have been reclassified to conform to the current period’s presentation. Such reclassifications have no effect on the reported results in the current or prior period.

Use of Estimates

The accompanying Interim Financial Statements have been prepared in accordance with U.S. GAAP. The preparation of financial statements in conformity with U.S. 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 from those estimates. Osage’s consolidated financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties, as well as the cost and timing of its asset retirement obligations.

Cash and Equivalents

Cash and equivalents include cash in banks and financial instruments which mature within three months of the date of purchase.

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 $3,659,448 are being amortized over the term of the Note Purchase Agreement on a straight-line basis.

Deferred financing costs at March 31, 2013 were $2,610,010. Amortization of deferred financing costs was $314,462 for the three months ended March 31, 2013. There were no deferred financing fees amortized during the three months ended March 31, 2012.

Restricted Cash

In connection with the Boothbay Secured Promissory Note (see Note 5) the Company is required to deposit certain royalty interests of Boothbay’s into joint accounts held by the Company for the benefit of Boothbay. These royalty interests at March 31, 2013 were $166,090, compared to $102,467 at December 31, 2012. The Company has also pledged $55,000 for certain bonds and sureties.

F-5

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 months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013			2012
Net (loss) income allocable to common shares	$	(73,425	)	$	456,026
Basic and diluted net (loss) income per share	$	(0.00	)	$	0.01
Basic and diluted weighted average shares outstanding		49,481,632			47,949,061

Potential common shares consisted of 3,071,843 and 1,125,000 warrants to purchase common stock at March 31, 2013 and 2012, respectively. These were excluded from the computations as their effect would have been anti-dilutive.

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:

	March 31, 2013			December 31, 2012
Properties subject to amortization	$	15,907,619		$	10,390,990
Properties not subject to amortization		1,444,747			1,362,325
Capitalized asset retirement costs		24			19
Accumulated depreciation and depletion		(2,095,809	)		(1,830,204	)
Oil & gas properties, net	$	15,256,581		$	9,923,130

F-6

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 is responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty payments, is allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson will be the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’ acreage controls the section. In sections where the Parties’ acreage does not control the section, we may elect to participate in wells operated by others. The Company continues to acquire additional acreage in the Nemaha Ridge prospect and will offer the additional acreage to the Parties, at its cost, subject to their acceptance. At March 31, 2013, the Company had 7,950 net acres (48,187 gross) leased in Logan County. In December 2011, the Company began drilling its first well in Logan County and at March 31, 2013 the Company had participated, or was participating, in drilling 19 wells, seven of which had achieved production and revenues by March 31, 2013. As of March 31, 2013, the Company had also completed four salt water disposal wells.

In addition to accumulating leases in Logan County, in 2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, the Company purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect 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. As of March 31, 2013, the Company had 3,579 net acres (3,925 gross) leased in Pawnee County. As of March 31, 2013, none of these leases have been assigned to B&W.

In 2011, the Company began to acquire leases in Coal County, Oklahoma, targeting the Oily Woodford Shale formation. At March 31, 2013, we had 4,253 net (9,509 gross) acres leased in Coal County.

At March 31, 2013, the Company had leased an aggregate of 15,782 net (61,621 gross) acres across three counties in Oklahoma.

4. SEGMENT AND GEOGRAPHICAL INFORMATION

The Company operates in two segments and has activities in two geographical regions. The Oil / Gas segment engages primarily in the acquisition, development, production and sale of oil, gas and natural gas liquids. The Pipeline segment engages primarily in the transport of oil.

The following tables set forth revenues, income and assets by segment for the periods presented:

Three Months Ended March 31, 2013

	Oil/Gas		Pipeline		Total
Income Statement Data:
Operating revenues	$	1,827,559	$	599,192	$	2,426,751
Total revenues		1,827,559		599,192		2,426,751
Depreciation, depletion & amortization		316,869		8,928		325,797
Other allocable operating expenses		475,074		169,860		644,934
Gross profit	$	1,035,616	$	420,404	$	1,456,020
Corporate general and administrative expenses						755,879
Operating income						700,141
Corporate interest expense						(773,754	)
Corporate Interest income						188
Loss from continuing operations before income taxes					$	(73,425	)
Balance Sheet Data:
Segment assets	$	15,256,581	$	620,656	$	15,877,237
Segment assets	$	15,256,581	$	620,656		15,877,237
Corporate assets						4,866,532
Consolidated assets					$	20,743,769

F-7

Three Months Ended March 31, 2012

	Oil/Gas		Pipeline		Total
Income Statement Data:
Operating revenues	$	885,628	$	469,891	$	1,355,519
Total revenues		885,628		469,891		1,355,519
Depreciation, depletion & amortization		118,351		1,725		120,076
Other allocable operating expenses		236,415		197,100		433,515
Gross profit	$	530,863	$	271,066	$	801,928
Corporate general and administrative expenses						346,136
Operating income						455,792
Corporate interest expense						(606	)
Corporate Interest income						840
Income from continuing operations before income taxes					$	456,026
Balance Sheet Data:
Segment assets	$	4,538,373	$	205,940	$	4,744,313
Segment assets	$	4,538,373	$	205,940		4,744,313
Corporate assets						1,509,371
Consolidated assets					$	6,253,684

The following table sets forth revenues and assets by geographic location for the periods presented:

	Revenues for the					Revenues for the
	Three Months ended March 31, 2013					Three Months ended March 31, 2012
	Amount		% of Total			Amount		% of Total
Colombia	$	1,214,879		50.1	%	$	1,022,384		75.4	%
United States		1,211,872		49.9	%		333,135		24.6	%
Total	$	2,426,751		100.0	%	$	1,355,519		100.0	%

	Long Lived Assets at					Long Lived Assets at
	March 31, 2013					December 31, 2012
	Amount		% of Total			Amount		% of Total
Colombia	$	2,887,959		15.9	%	$	2,975,601		23.7	%
United States		15,262,482		84.1	%		9,593,297		76.3	%
Total	$	18,150,441		100.0	%	$	12,568,898		100.0	%

5. DEBT

2013 Activity

Helm Bank, Colombia – Unsecured Term Loan

In January 2013, the Company entered into a two year unsecured term loan facility with Helm Bank, Colombia in the amount of $367,521 in order to avail of an amnesty program for certain 2003 Colombian equity taxes, as more fully discussed in Note 6. The principal is payable in 24 equal installments and the interest rate is variable. As of March 31, 2013 there was $336,893 outstanding under this term loan. The Company recognized $7,248 of interest expense related to this term loan in the three months ended March 31, 2013.

F-8

2012 Activity

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. As of March 31, 2013, the amount outstanding under the Note Purchase Agreement was $7,000,000 and we drew down $4,000,000 in the three months then ended.

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.

The Company recorded deferred financing costs in the aggregate amount of $3,659,448 in connection with the Note Purchase Agreement, which represented the fair value of warrants issued to Apollo and CCNRP, placement fees and legal fees, which are amortized on a straight-line basis over the term of the Notes 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 also obligated to pay a quarterly standby fee, which accrues at a rate of 3.0%, on the amount of undrawn funds equal to the difference between $5,000,000 and the aggregate principal amount of notes issued on or after the closing date. 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 3 months of interest payments.

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 amendment also provided a limited waiver of certain covenants as of March 31, 2013, as the Company did not meet certain covenants including the minimum production covenant as of that date.

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. Financial covenants include a $75,000 limitation per quarter on general and administrative costs in excess of the revenues generated by Cimarrona, LLC and the following:

Each Quarter Ending:	Interest Coverage Ratio	Minimum Production (MBbls)	Asset Coverage Ratio
June 30, 2013	1.10 to 1.00	35	1.00 to 1.00
September 30, 2013	1.75 to 1.00	50	1.25 to 1.00
December 31, 2013	2.25 to 1.00	60	1.50 to 1.00
March 31, 2014	2.50 to 1.00	70	1.75 to 1.00
June 30, 2014	3.00 to 1.00	80	2.00 to 1.00
September 30, 2014	3.00 to 1.00	90	2.00 to 1.00
December 31, 2014, and thereafter	3.00 to 1.00	100	2.00 to 1.00

F-9

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 matures April 17, 2014 and bears interest of 18%, payable monthly. In addition, Boothbay received 400,000 shares 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 is 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.

In connection with the Note Purchase Agreement and the Secured Promissory Note, the Company recognized $766,505 of interest expense, of which $357,727 was non-cash interest expense, for the three month ended March 31, 2013. Cash interest expense related to the Note Purchase Agreement and the Secured Promissory Note represented $408,778 for the three months ended March 31, 2013. No interest expense related to these facilities was recognized in the three months ended March 31, 2012.

6. 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 March 31, 2013, 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.

Land Rentals and Operating Leases

In February 2011, the Company entered into a 36 month lease for its corporate offices in San Diego. The lease, including parking, was initially for $3,488 per month for the first year, increasing to $3,599 and $3,715 in the second and third years, respectively. In addition, the Company is responsible for all operating expenses and utilities. The lease required the Company to increase its security deposit from $3,381 to $10,000, with $3,299 and $3,415 of the security deposit to be applied to months 13 and 25, respectively, of the lease. In February 2012, the Company entered into a 24 month lease for a vehicle to be utilized by its operations in Oklahoma. Lease payments are $680 per month. Apart from the San Diego office and Oklahoma vehicle lease, the Company’s Oklahoma office and all leased equipment are under month-to-month operating leases. Rental expense totaled $14,364 and $14,039 for the three months ended March 31, 2013 and 2012, respectively.

Future minimum commitments under operating leases are as follows as of March 31, 2013:

Year	Amount
2013 (April 1 - December 31)		34,120
2014		8,190
	$	42,310

F-10

Legal Proceedings

The Company is not party to any litigation arisen in the normal course of its business and 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 in the amount of $548,092. 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 will recognize the benefit of the amnesty upon final acceptance and receipt of official confirmation that the liability is fully settled. The Company recognized $32,964 and $32,802 in current equity tax for the three months ended March 31, 2013 and 2012, respectively.

7. MAJOR CUSTOMERS

During the three months ended March 31, 2013 and 2012, the Company had five and four customers, respectively, which accounted for all of its sales:

	Three Months ended					Three Months ended
	March 31, 2013					March 31, 2012
	Amount		% of Total			Amount		% of Total
Slawson	$	952,071		39.2	%	$	320,853		23.7	%
HOCOL		615,687		25.4	%		552,493		40.8	%
Pacific		599,192		24.7	%		469,891		34.7	%
Devon		177,922		7.3	%		-		0.0	%
Stephens		81,879		3.4	%		-		0.0	%
Coffeyville		-		0.0	%		12,282		0.9	%
Total	$	2,426,751		100.0	%	$	1,355,519		100.0	%

8. 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 statement 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 March 31, 2013 and December 31, 2012, 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 quarter ended March 31, 2013 is as follows:

	Three Months Ended March 31, 2013
	Colombia		United States		Combined
Beginning balance	$	-	$	19	$	19
Incurred during the period		-		-		-
Reversed during the period		-		-		-
Additions for new wells		-		5		5
Accretion expense		-		1		1
Ending balance	$	-	$	25	$	25

F-11

9. EQUITY

Common Stock

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. We will issue 50,000 shares on each of the first, second, and third anniversaries of the execution of the agreement subject to other terms and conditions of the agreement. The 150,000 shares were valued at $177,000, or $1.18 per share and are 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.

During the three months ended March 31, 2012, we issued 90,000 shares to a consultant for services to be provided from March through August 2012. All of the shares vested immediately with a fair value of $41,400, or $0.46 per share. As of March 31, 2012, $24,900 of expense related to the shares issued was recorded as a prepaid expense and $16,500 of stock based compensation was recognized in the first quarter of 2012.

Total stock-based compensation expense was $378,750 and $16,500 for the three months ended March 31, 2013 and 2012, respectively.

10. SUBSEQUENT EVENTS

On April 5, 2013, we amended the Note Purchase Agreement with Apollo as more fully discussed in Note 5 above, increasing the total facility to $20,000,000 from $10,000,000, and drew down an additional $5,000,000 in borrowings under the expanded facility. We paid an amendment fee of $100,000 in connection with the amendment. In addition, 1,125,000 warrants to purchase common stock expired unexercised on April 8, 2013 and on April 11, 2013 CCNRP exercised their warrants to purchase 350,000 shares of common stock.

F-12

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. 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 and their partnership interest may increase thereafter to 70% based on oil production results. We believe Ecopetrol could become a 50% partner in the future, which would effectively reduce our cash flows from oil sales by 50%. In addition, in 2022, the Association Contract with Ecopetrol terminates, at which time we will have no economic interest remaining in this property. 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.

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 Oily Woodford Shale formations. The Mississippian formation may reach 600 feet in gross thickness and the targeted porosity zone is between 50 and 300 feet thick. 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, horizontal 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, we entered into a participation agreement (the “Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE”). 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, Slawson and USE carried Osage for 7.5% of the cost of the first three horizontal Mississippian wells, such 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 is responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty payments, is allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson will be the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’ acreage controls the section. In sections where the Parties’ acreage does not control the section, we may elect to participate in wells operated by others. We are acquiring additional acreage in the Nemaha Ridge prospect and will offer the additional acreage to Slawson and USE, at our cost, subject to their acceptance. The Participation Agreement states that Osage will deliver acreage in the Nemaha Ridge Prospect to the Parties at a net Revenue Interest (“NRI”) of 78% unless Osage acquires the acreage at an NRI lower than 78%, in which case, the acreage will be delivered at the NRI acquired by Osage. Where Osage acquires leases with an NRI in excess of 78%, it will retain an overriding royalty interest (“ORRI”) equal to the difference between the NRI and 78%. At March 31, 2013, the Company had 7,950 net acres (48,187 gross) leased in Logan County. In December 2011, the Company began drilling its first well in Logan County and at March 31, 2013 the Company had participated, or was participating, in drilling 19 wells, seven of which had achieved production and revenues by March 31, 2013. As of March 31, 2013, the Company had also completed four salt water disposal wells.

3

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. As of March 31, 2013, the Company had 3,579 net acres (3,925 gross) leased in Pawnee County. As of March 31, 2013, 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 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 March 31, 2013, we had 4,253 net (9,509 gross) acres leased in Coal County.

At March 31, 2013, we had leased an aggregate of 15,782 net (61,621 gross) acres across three counties in Oklahoma as follows:

	Gross		Osage Net
Logan		48,187		7,950
Pawnee		3,925		3,579
Coal		9,509		4,253
		61,621		15,782

We have accumulated deficits of $8,148,211 (unaudited) at March 31, 2013 and $8,074,786 at December 31, 2012. Substantial portions of the losses are attributable to asset impairment charges, stock-based compensation, professional fees and interest expense. We also had working capital deficits of $1,095,336 and $643,843 as of March 31, 2013 and December 31, 2012, respectively.

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) assigning a portion of our oil and gas leases in Logan County, Oklahoma, (b) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and expenses and (d) raising additional equity and/or debt.

On April 17, 2012, we issued a secured promissory note (“Secured Promissory Note”) to Boothbay Royalty Co. (Boothbay) for $2,500,000. On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement”) with Apollo Investment Corporation (“Apollo”) and on April 5, 2013 we amended the Note Purchase Agreement, increasing the total facility to $20,000,000 (see Note 5 - Debt, in the accompanying unaudited consolidated financial statements). We anticipate that we will draw down the full $20,000,000 available to us under the Note Purchase Agreement during the next 12 months to support the drilling in Logan County, as well as the other counties in Oklahoma.

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. To date, management has not considered this alternative, nor does management view it as a likely occurrence.

4

Results of Operations

Three Months ended March 31, 2013 compared to Three Months ended March 31, 2012

Our total revenues for the three months ended March 31, 2013 and 2012 comprised the following:

	2013					2012					Change
	Amount		Percentage			Amount		Percentage			Amount		Percentage
Revenues
Oil sales	$	1,703,526		70.2	%	$	873,125		64.4	%	$	830,401		95.1	%
Pipeline sales		599,192		24.7	%		469,891		34.7	%		129,301		27.5	%
Natural gas sales		124,033		5.1	%		12,503		0.9	%		111,530		892.0	%
Total revenues	$	2,426,751		100.0	%	$	1,355,519		100.0	%	$	1,071,232		79.0	%

Oil Sales

Oil Sales were $1,703,526, an increase of $830,401, or 95.1%, for the three months ended March 31, 2013 compared to $873,125 for the three months ended March 31, 2012. Oil sales increased due to an increase in the number of barrels sold partially offset by a reduction in the average price per barrel. In the United States (“US”), we sold 12,115 barrels (“BBLs”) at an average price of $89.79 in the 2013 period, compared to 3,154 BBLs at an average price of $99.51 in the 2012 period. In Colombia, we sold 6,000 BBLs at an average price of $106.34 in the 2013 period compared to 5,000 BBLs at an average price of $114.51 in the 2012 period. We began well production in Logan County, Oklahoma, in the first quarter of 2012, which accounted for the majority of the increase in oil sales in the United States as we continue to participate in developing wells in that region.

Pipeline Sales

The Guaduas pipeline connects with the ODC pipeline (the “ODC Pipeline”) to transport oil to the port of Covenas in Colombia. Pipeline sales were $599,192, an increase of $129,301, or 27.5% for the three months ended March 31, 2013 compared to $469,891 for the three months ended March 31, 2012, primarily due to an increase in the number of barrels transported. The number of barrels transported was 3.17 million BBLS (our share was approximately 298,000) and 2.45 million BBLs (our share was approximately 234,000) in the three months ended March 31, 2013 and 2012, respectively.

Natural Gas Sales

Natural gas sales were $124,033 for the three months ended March 31, 2013 compared to $12,503 for the three months ended March 31, 2012, an increase of $111,530, or 892.0%. All of our natural gas sales are from the well production in Logan County, Oklahoma.

Total revenues were $2,426,751, an increase of $1,071,232, or 79.0% for the three months ended March 31, 2013 compared to $1,355,519 for the three months ended March 31, 2012. Oil sales accounted for 70.2% and 64.4% of total revenues in the 2013 and 2012 periods, respectively.

Production

For the three months ended March 31, 2013 and 2012, our production, net of royalties, was as follows:

	2013					2012					Increase/(Decrease)
Oil Production:	Net Barrels		% of Total			Net Barrels		% of Total			Barrels		%
United States		12,160		69.8	%		3,124		46.2	%		9,036		289.2	%
Colombia		5,267		30.2	%		3,635		53.8	%		1,632		44.9	%
Total		17,427		100.0	%		6,759		100.0	%		10,668		157.8	%
Natural Gas Production:	Mcf		% of Total			Mcf		% of Total			Mcf		%
United States		26,568		100.0	%		2,393		100.0	%		24,175		1010.2	%

Oil production, net of royalties, was 17,427 BBLs (21,892 BBLs gross), an increase of 10,688 BBLs, or 157.8% for the three months ended March 31, 2013 compared to 6,759 BBLs (8,617 BBLs gross) for the three months ended March 31, 2012, primarily due to production increases in the U.S. U.S. production accounted for 69.8% and 46.2% of total production for the three months ended March 31, 2013 and 2012, respectively.

Natural gas production, net of royalties, was 26,568 thousand cubic feet (“Mcf”) (34,308 Mcf gross) for the three months ended March 31, 2013, an increase of 24,175 Mcf, or 1010.2% over the 2012 period. Gas production began in the first quarter of 2012 in our Logan County properties, and production, net of royalties, for that period was 2,393 Mcf (3,128 Mcf gross).

5

Operating Costs and Expenses

For the three months ended March 31, 2013 and 2012, our operating costs and expenses were as follows:

	2013					2012					Change
			Percent of					Percent of
	Amount		Sales			Amount		Sales			Amount		Percentage
Operating Expenses
Operating	$	498,909		20.6	%	$	304,866		22.5	%	$	194,043		63.6	%
General & administrative		865,500		35.7	%		438,429		32.3	%		427,071		97.4	%
Equity tax		32,964		1.4	%		32,802		2.4	%		162		0.5	%
Depreciation, depletion and accretion		329,237		13.6	%		123,630		9.1	%		205,607		166.3	%
Total operating expenses	$	1,726,610		71.1	%	$	899,727		66.4	%	$	826,883		91.9	%
Operating income	$	700,141		28.9	%	$	455,792		33.6	%	$	244,349		53.6	%

Operating Costs

Our operating costs were $498,909 for the three months ended March 31, 2013 compared to $304,866 for the three months ended March 31, 2012, due primarily to an increase in operating costs in the U.S. as a result of having seven wells in production in Logan County at March 31, 2013. Operating costs as a percentage of total revenues reduced to 20.6% in the 2013 period from 22.5% in 2012 period, as the percentage increase in revenues was much greater than the percentage increase in operating costs as new wells came into production. Operating costs as a percentage of revenues also declined as a result of the increased percentage of U.S. production, to 69.8% in the 2012 period from 46.2% in the 2012 period as average production cost per barrel of oil equivalent (“Production Cost/BOE”) in the U.S. for the three months ended March 31, 2013 was $10.99 compared to the average cost in Colombia of $34.71. Our average total Production Cost/BOE for the three months ended March 31, 2013 was $16.71.

General and Administrative Expenses

General and administrative expenses were $865,500 for the three months ended March 31, 2013, an increase of $427,071 or 97.4%, compared to $438,429 for the three months ended March 31, 2012. As a percent of total revenues, general and administrative expenses increased to 35.7% in the 2013 period from 32.3% in the 2012 period. The increase of $427,071 was primarily due to an increase in stock based compensation of $362,250. The increase in stock based compensation expense for the three months ended March 31, 2013 related to the issuance of more shares in the current period than in the prior year period. Stock based compensation for the three months ended March 31, 2013 was $378,750, compared to $16,500 in the three months ended March 31, 2012.

Equity Tax

Equity tax was $32,964 for the three months ended March 31, 2013 and $32,802 for the three months ended March 31, 2012. Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona LLC.

Depreciation, depletion and accretion

Depreciation, depletion and accretion were $329,237 for the three months ended March 31, 2013 and $123,630 for the three months ended March 31, 2012, an increase of $205,607 or 166.3%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.

Operating Income

Operating income was $700,141 for the three months ended March 31, 2013 compared to $455,792 for the three months ended March 31, 2012. The improvement in operating income is as a result of revenue growth of $1,071,232 which exceeded operating expense growth of $826,883.

6

Interest Expense

Interest expense was $773,754 for the three months ended March 31, 2013 compared to $606 for the three months ended March 31, 2012, an increase of $773,148. The increase in interest expense during the 2013 period was primarily due to deferred financing fees amortization, interest expense, standby fees and debt discount amortization in connection with the Note Purchase Agreement and Secured Promissory Note. In the three months ended March 31, 2013, cash interest expense amounted to $416,026. The remaining non-cash interest expense of $357,728 consisted primarily of deferred financing fees of $314,462 and debt discount amortization of $43,265.

Provision for Income Taxes

Provision for income taxes was zero for the three months ended March 31, 2013 and 2012. 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.

Net Income / (Loss)

Net loss was $73,425 for the three months ended March 31, 2013 compared to net income of $456,026 for the three months ended March 31, 2013. The $529,451 reduction was as a result of increased interest expense in the current period, partially offset by an improvement in operating income.

Foreign Currency Translation Gain / (Loss)

Foreign currency translation gain was $23,563 for the three months ended March 31, 2013 compared to a foreign currency translation loss of $3,664 for the three months ended March 31, 2012. The Colombian Peso to Dollar Exchange Rate averaged 1,791 and 1,800 for the three month periods ended March 31, 2013 and 2012, respectively and was 1,825 and 1,765 at March 31, 2013 and December 31, 2012.

Comprehensive Income / (Loss)

Comprehensive loss was $49,862 for the three months ended March 31, 2013 compared to comprehensive income of $452,362 for the three months ended March 31, 2012. The $502,224 reduction was as a result of the $529,451 reduction in net income to a net loss in the current period compared to the prior year period, partially offset by the foreign currency translation gain in the three months ended March 31, 2013 compared to a foreign currency loss in the prior year period.

Liquidity and Capital Resources

Net cash provided by operating activities totaled $1,918,822 for the three months ended March 31, 2013, compared to $559,174 for the three months ended March 31, 2012. The major components of net cash provided by operating activities for the three months ended March 31, 2013 included non-cash activities which consisted of shares issued for services of $378,750, provision for depreciation, depletion and accretion of $329,237, amortization of deferred financing costs of $314,462 and amortization of debt discount of $43,265. Other components included the $1,912,332 increase in accounts payable due primarily to our Oklahoma operations related to well production and drilling, and partially offset by a decrease of $609,665 in accrued expenses and an increase in accounts receivable of $428,976. Net cash provided by operating activities for the three months ended March 31, 2012 totaled $559,174. The major components of the net cash provided by operating activities in 2012 were the $456,026 net income, the $349,735 increase in accounts payable and accrued expenses and the $123,630 provision for depreciation, partially offset by the $340,001 increase in accounts receivable.

Net cash used in investing activities totaled $5,750,036 for the three months ended March 31, 2013 and consisted primarily of investments in oil and gas wells. Net cash used investing activities in 2012 totaled $1,712,067 and consisted primarily of $2,689,623 investment in oil and gas properties, partially offset by $977,556 net proceeds from assignment of leases.

Net cash provided by financing activities totaled $4,336,893 for the three months ended March 31, 2013 and consisted of $4,000,000 proceeds from the Note Purchase Agreement and $367,521 proceeds from a Colombian term loan, partially offset by $30,628 in principal payments on the term loan, Net cash used by financing activities amounted to $100,000 in the three months ended March 31, 2012, consisting entirely of payment of deferred financing costs related to the Apollo 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.

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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 Hocol in Colombia and Slawson, Devon, and Stephens 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. We are subject to changes in the price of oil and exchange rates of the Colombian Peso, which are out of our control. In our Logan county properties, we sold oil and gas at prices ranging from $86.49 to $93.75 per barrel and $3.51 to $6.52 per Mcf in the three months ended March 31, 2012. In our Osage properties we sold oil at prices ranging from $99.51 to $105.22 in the three months ended March 31, 2012. In our Cimarrona property in Colombia, we sold oil at prices ranging from $96.45 to $108.20 per barrel during the three months ended March 31, 2013 compared to $107.65 to $119.00 during the three months ended March 31, 2012. The Colombian Peso to Dollar Exchange Rate averaged approximately 1,791 and 1,800 during the three months ended March 31, 2013 and 2012, respectively. The Colombian Peso to Dollar Exchange Rate was 1,824 and 1,791 at March 31, 2013 and 2012, respectively.

We have exposure to changes in interest rates as our largest debt facility is tied to the London inter-bank overnight rate (“Libor”).

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 nine months ended March 31, 2013 or 2012. 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 March 31, 2013 and 2012 our oil production operations were conducted in Colombia and 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. The Company follows the sales method of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids sold to purchasers, regardless of whether its sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent the Company has an imbalance on a specific property greater than the expected remaining reserves.

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Off-Balance Sheet Arrangements

Our Company has not entered into any transaction, agreement or other contractual arrangement with an entity unconsolidated with us 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

The 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, 2013, 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 March 31, 2013 is not effective, that, as of March 31, 2013, 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 three months ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR.

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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

The 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

On January 2, 2013 we issued a total of 400,000 shares of common stock to two employees for services rendered.

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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf of the undersigned thereunto duly authorized.

	OSAGE EXPLORATION AND DEVELOPMENT, INC. (Registrant)
Date: May 13, 2013	By:	/s/ Kim Bradford
		Kim Bradford
		President and Chief Executive Officer
Date: May 13, 2013	By:	/s/ Norman Dowling
		Norman Dowling
		Chief Financial Officer

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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

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