News Column

OSAGE EXPLORATION & DEVELOPMENT, INC. - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations.

August 14, 2014

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. 3 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.



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 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. 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. 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. 4 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. 5

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. 6 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. 7



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. 8



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. 9 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. 10 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. 11 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.


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Source: Edgar Glimpses


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