OEDVQ Osage Exploration and Development Inc (CE)

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 June 30, 2013, the Company had 8,109 net acres (48,026 gross) leased in Logan County. In December 2011, the Company began drilling its first well in Logan County and at June 30, 2013 the Company had participated, or was participating, in drilling 29 wells, 17 of which had achieved production and revenues by June 30, 2013. As of June 30, 2013, the Company had also completed four salt water disposal wells.

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 June 30, 2013, the Company had 4,190 net acres (5,085 gross) leased in Pawnee County. As of June 30, 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 June 30, 2013, we had 4,253 net (9,509 gross) acres leased in Coal County.

In 2013, the partners in the Participation Agreement began to acquire leases in southern Garfield County, Oklahoma, just north of the Nemaha Ridge prospect in Logan County. At June 30, 2013, we had 445 net (2,240 gross) acres leased in Garfield County.

At June 30, 2013, we had leased an aggregate of 16,997 net (64,860 gross) acres across four counties in Oklahoma as follows:

We have accumulated deficits of $8,117,509 (unaudited) at June 30, 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 $14,317,536 and $643,843 as of June 30, 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 for consideration 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). As of June 30, 2013, as a result of production delays outside of the Company’s control, the Company was not in compliance with certain covenants including the minimum production covenant of 35 MBbls at that date.

On August 12, 2013, the Company and Apollo amended the Note Purchase Agreement. This amendment provided a waiver for certain covenants with which the Company was not in compliance as of June 30, 2013. The amendment also provided for an immediate drawdown of additional proceeds of $2 million under the Note Purchase Agreement, which the Company drew down on August 12, 2013. The amendment requires that the Company, within 75 days of the effective date as defined in the amendment, complete either (1) a sale of certain assets for net proceeds of not less than $8 million, or (2) the issuance of capital stock in a transaction that results in aggregate net proceeds as defined in the amendment of not less than $5 million. In the event that the Company does not complete either one of the aforementioned transactions, the Company is required under the terms of the amendment to issue to Apollo additional warrants equivalent to three percent of the Company’s common stock, on a fully-diluted basis. There can be no assurance that additional funds will be available under the Note Purchase Agreement.

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.

Results of Operations

Three Months ended June 30, 2013 compared to Three Months ended June 30, 2012

Our total revenues for the three months ended June 30, 2013 and 2012 comprised the following:

Oil Sales

Oil Sales were $1,681,559, an increase of $780,135, or 86.5%, for the three months ended June 30, 2013 compared to $901,424 for the three months ended June 30, 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 13,264 barrels (“BBLs”) at an average price of $91.64 in the 2013 period, compared to 6,000 BBLs at an average price of $95.68 in the 2012 period. In Colombia, we sold 5,000 BBLs at an average price of $96.40 in the 2013 period compared to 3,000 BBLs at an average price of $109.72 in the 2012 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 majority of the increase in oil sales in the United States.

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 $611,920, an increase of $194,151, or 46.5% for the three months ended June 30, 2013 compared to $417,769 for the three months ended June 30, 2012, primarily due to an increase in the number of barrels transported. The number of barrels transported was 3.24 million BBLS (our share was approximately 305,000) and 2.21 million BBLs (our share was approximately 208,000) in the three months ended June 30, 2013 and 2012, respectively.

Natural Gas Sales

Natural gas sales comprise revenues from the sale of natural gas and natural gas liquids. Natural gas sales were $96,782 for the three months ended June 30, 2013 compared to $40,623 for the three months ended June 30, 2012, an increase of $56,159, or 138.2%. All of our natural gas sales are from the well production in Logan County, Oklahoma.

Total revenues were $2,390,261, an increase of $1,030,445, or 75.8% for the three months ended June 30, 2013 compared to $1,359,816 for the three months ended June 30, 2012. Oil sales accounted for 70.4% and 66.3% of total revenues in the 2013 and 2012 periods, respectively.

Oil production, net of royalties, was 17,741 BBLs, an increase of 7,391 BBLs, or 71.4% for the three months ended June 30, 2013 compared to 10,350 BBLs for the three months ended June 30, 2012, primarily due to production increases in the U.S. U.S. production accounted for 76.6% and 59.9% of total production for the three months ended June 30, 2013 and 2012, respectively.

Natural gas production was 19,076 thousand cubic feet (“Mcf”) for the three months ended June 30, 2013, an increase of 9,555 Mcf, or 100.4% over the production of 9,521 Mcf in the 2012 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, with net production of 647 BBLs.

Operating Costs

Our operating costs were $719,079 for the three months ended June 30, 2013 compared to $422,993 for the three months ended June 30, 2012, due primarily to an increase in operating costs in the U.S. as a result of having 17 wells in production in Logan County at June 30, 2013. Operating costs as a percentage of total revenues reduced to 30.1% in the 2013 period from 31.1% in 2012 period, as the percentage increase in revenues was 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. oil production, to 76.6% in the 2013 period from 59.9% 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 June 30, 2013 was $20.55 compared to the average cost in Colombia of $45.53. Our average total Production Cost/BOE for the three months ended June 30, 2013 was $25.37.

General and Administrative Expenses

General and administrative expenses were $575,507 for the three months ended June 30, 2013, a decrease of $387,684 or 40.2%, compared to $963,191 for the three months ended June 30, 2012. As a percent of total revenues, general and administrative expenses decreased to 24.1% in the 2013 period from 70.8% in the 2012 period. The decrease of $387,684 was primarily due to a decrease in stock based compensation of $465,061, and reductions in legal and professional fees, offset by increases in salaries and insurance costs. The decrease in stock based compensation expense for the three months ended June 30, 2013 related to the issuance of less shares in the current period than in the prior year period. Stock based compensation for the three months ended June 30, 2013 was $26,750, compared to $491,811 in the three months ended June 30, 2012.

Equity Tax

Current equity tax was $31,723 for the three months ended June 30, 2013 and $32,802 for the three months ended June 30, 2012. Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. In January 2013, we successfully concluded negotiations with DIAN with respect to the ultimate liability for the 2003 tax year. DIAN waived certain interest and penalties. We paid the agreed final liability to DIAN in January 2013 and recognized the $531,644 benefit of the amnesty in the quarter ended June 30, 2013, upon receipt of confirmation from DIAN that the liability is fully settled.

Depreciation, depletion and accretion

Depreciation, depletion and accretion were $390,393 for the three months ended June 30, 2013 and $215,393 for the three months ended June 30, 2012, an increase of $175,000 or 81.2%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.

Operating Income

Operating income was $1,205,204 for the three months ended June 30, 2013 compared to an operating loss of $274,563 for the three months ended June 30, 2012. The improvement in operating income is as a result of revenue growth of $1,030,445 and a reduction in operating expenses of $449,332, driven primarily by the reduction in stock based compensation expense and the recognition of the benefit of the amnesty for 2003 equity tax in the three months ended June 30, 2013.

Interest Expense

Interest expense was $1,138,848 for the three months ended June 30, 2013 compared to $341,159 for the three months ended June 30, 2012, an increase of $797,689. The increase in interest expense during the 2013 period was primarily due to interest expense, deferred financing fees amortization, standby fees and debt discount amortization in connection with the Note Purchase Agreement and Secured Promissory Note. In the three months ended June 30, 2013, cash interest expense amounted to $763,736. 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 $36,690 for the three months ended June 30, 2013 as a result of marking open financial derivative instruments to market as of June 30, 2013. There were no open financial derivative instruments as of June 30, 2012.

Provision for Income Taxes

Provision for income taxes was zero for the three months ended June 30, 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 income was $30,702 for the three months ended June 30, 2013 compared to net loss of $613,484 for the three months ended June 30, 2012. The $644,186 increase was as a result of the improvement in operating income, partially offset by increased interest expense and oil and gas derivatives in the current period.

Foreign Currency Translation Loss

Foreign currency translation loss was $849 for the three months ended June 30, 2013 compared to $3,835 for the three months ended June 30, 2012. The Colombian Peso to Dollar Exchange Rate averaged 1,861 and 1,785 for the three month periods ended June 30, 2013 and 2012, respectively and was 1,828 and 1,765 at June 30, 2013 and December 31, 2012.

Comprehensive Income / (Loss)

Comprehensive income was $29,853 for the three months ended June 30, 2013 compared to a comprehensive loss of $617,319 for the three months ended June 30, 2012. The $647,172 increase was as a result of the $644,186 increase from a net loss to net income in the current period compared to the prior year period, partially offset by the reduction in foreign currency translation loss in the three months ended June 30, 2013 compared to the prior year period.

Six Months ended June 30, 2013 compared to Six Months ended June 30, 2012

Our total revenues for the six months ended June 30, 2013 and 2012 comprised the following:

Oil Sales

Oil Sales were $3,385,085, an increase of $1,610,536, or 90.8%, for the six months ended June 30, 2013 compared to $1,774,549 for the six months ended June 30, 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 25,149 barrels (“BBLs”) at an average price of $92.04 in the 2013 period, compared to 9,189 BBLs at an average price of $99.30 in the 2012 period. In Colombia, we sold 11,000 BBLs at an average price of $101.82 in the 2013 period compared to 8,000 BBLs at an average price of $112.71 in the 2012 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 majority of the increase in oil sales in the United States.

Pipeline Sales

Pipeline sales were $1,211,112, an increase of $323,452, or 36.4% for the six months ended June 30, 2013 compared to $887,660 for the six months ended June 30, 2012, primarily due to an increase in the number of barrels transported. The number of barrels transported was 6.41 million BBLS (our share was approximately 603,000) and 4.70 million BBLs (our share was approximately 442,000) in the six months ended June 30, 2013 and 2012, respectively.

Natural Gas Sales

Natural gas sales comprise revenues from the sale of natural gas and natural gas liquids. Natural gas sales were $220,815 for the six months ended June 30, 2013 compared to $53,126 for the six months ended June 30, 2012, an increase of $167,689, or 315.6%. All of our natural gas sales are from the well production in Logan County, Oklahoma.

Total revenues were $4,817,012, an increase of $2,101,677, or 77.4% for the six months ended June 30, 2013 compared to $2,715,335 for the six months ended June 30, 2012. Oil sales accounted for 70.3% and 65.4% of total revenues in the 2013 and 2012 periods, respectively.

Oil production, net of royalties, was 35,168 BBLs, an increase of 18,059 BBLs, or 105.6% for the six months ended June 30, 2013 compared to 17,109 BBLs for the six months ended June 30, 2012, primarily due to production increases in the U.S. U.S. production accounted for 73.2% and 54.5% of total production for the six months ended June 30, 2013 and 2012, respectively.

Natural gas production was 45,644 Mcf for the six months ended June 30, 2013, an increase of 33,712 Mcf, or 282.5% over production of 11,932 Mcf in the 2012 period. Natural 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, with net production of 647 BBLs.

Operating Costs

Our operating costs were $1,217,988 for the six months ended June 30, 2013 compared to $727,859 for the six months ended June 30, 2012, due primarily to an increase in operating costs in the U.S. as a result of having 17 wells in production in Logan County at June 30, 2013. Operating costs as a percentage of total revenues reduced to 25.3% in the 2013 period from 26.8% in 2012 period, as the percentage increase in revenues was 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. oil production, to 73.2% in the 2013 period from 54.5% in the 2012 period as average Production Cost/BOE in the U.S. for the six months ended June 30, 2013 was $15.89 compared to the average cost in Colombia of $39.48. Our average total Production Cost/BOE for the six months ended June 30, 2013 was $21.01.

General and Administrative Expenses

General and administrative expenses were $1,441,007 for the six months ended June 30, 2013, an increase of $39,387 or 2.8%, compared to $1,401,620 for the six months ended June 30, 2012. As a percent of total revenues, general and administrative expenses decreased to 29.9% in the 2013 period from 51.6% in the 2012 period. The increase of $39,387 was primarily due to an increase in salaries and insurance, largely offset by a reduction in legal and professional fees and stock based compensation. The decrease in stock based compensation expense for the six months ended June 30, 2013 related to the issuance of fewer shares in the current period than in the prior year period. Stock based compensation for the six months ended June 30, 2013 was $405,500, compared to $508,311 in the six months ended June 30, 2012.

Equity Tax

Current equity tax was $64,686 for the six months ended June 30, 2013 and $65,604 for the six months ended June 30, 2012. DIAN, the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. In January 2013, we successfully concluded negotiations with DIAN with respect to the ultimate liability for the 2003 tax year. DIAN waived certain interest and penalties. We paid the agreed final liability to DIAN in January 2013 and recognized the $531,644 benefit of the amnesty in the six months ended June 30, 2013, upon receipt of confirmation from DIAN that the liability is fully settled.

Depreciation, depletion and accretion

Depreciation, depletion and accretion were $719,630 for the six months ended June 30, 2013 and $339,023 for the six months ended June 30, 2012, an increase of $380,607 or 112.3%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.

Operating Income

Operating income was $1,905,345 for the six months ended June 30, 2013 compared to $181,230 for the six months ended June 30, 2012. The improvement in operating income is as a result of revenue growth of $2,101,677 which exceeded operating expense growth of $377,562.

Interest Expense

Interest expense was $1,912,602 for the three months ended June 30, 2013 compared to $341,765 for the six months ended June 30, 2012, an increase of $1,570,837. The increase in interest expense during the 2013 period was primarily due to interest expense, deferred financing fees amortization, standby fees and debt discount amortization in connection with the Note Purchase Agreement and Secured Promissory Note. In the six months ended June 30, 2013, cash interest expense amounted to $1,179,763. 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 $36,690 for the six months ended June 30, 2013 as a result of marking open financial derivative instruments to market as of June 30, 2013. There were no open financial derivative instruments as of June 30, 2012.

Provision for Income Taxes

Provision for income taxes was zero for the six months ended June 30, 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 Loss

Net loss was $42,723 for the six months ended June 30, 2013 compared to $157,458 for the six months ended June 30, 2013. The $114,735 reduction in net loss was as a result of increased operating income, partially offset by increased interest expense.

Foreign Currency Translation Gain / (Loss)

Foreign currency translation gain was $22,714 for the six months ended June 30, 2013 compared to a foreign currency translation loss of $7,449 for the six months ended June 30, 2012. The Colombian Peso to Dollar Exchange Rate averaged 1,829 and 1,793 for the six month periods ended June 30, 2013 and 2012, respectively and was 1,928 and 1,765 at June 30, 2013 and December 31, 2012.

Comprehensive Loss

Comprehensive loss was $20,009 for the six months ended June 30, 2013 compared to comprehensive loss of $164,957 for the six months ended June 30, 2012. The $144,948 improvement was as a result of the $114,735 reduction in net loss in the current period compared to the prior year period and the foreign currency translation gain in the current period compared to a loss in the prior year period.

Liquidity and Capital Resources

Net cash used by operating activities totaled $502,191 for the six months ended June 30, 2013, compared to net cash provided of $1,470,147 for the six months ended June 30, 2012. 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 shares issued for services 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 $906,020 in accrued expenses and an increase in accounts receivable of $1,612,442. Net cash provided by operating activities for the six months ended June 30, 2012 totaled $1,470,147. The major components of the net cash provided by operating activities in 2012 were warrants issued for services of $448,111, provision for depreciation, depletion and accretion of $340,525, an increase in accounts payable of $964,331 and an increase in accrued expenses of $386,078, partially offset by an increase in accounts receivable of $807,999.

Net cash used in investing activities totaled $10,049,782 for the six months ended June 30, 2013 and consisted primarily of investments in oil and gas wells of $9,957,828. Net cash used investing activities in 2012 totaled $4,521,427 and consisted primarily of $7,289,333 investment in oil and gas properties, partially offset by $2,776,906 net proceeds from assignment of leases.

Net cash provided by financing activities totaled $10,178,873 for the six months ended June 30, 2013 and consisted of $10,000,000 proceeds from the Note Purchase Agreement and $367,520 proceeds from a Colombian term loan, partially offset by $92,147 in principal payments on the term loan and payment of additional deferred financing fees of $100,000, Net cash provided by financing activities amounted to $2,276,504 in the six months ended June 30, 2012, consisting of $2,500,000 proceeds from the Secured Promissory Note, partially offset by payment of deferred financing fees of $223,496.

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 Hocol in Colombia and Slawson, Devon, Stephens 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. 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 $90.28 to $94.27 per barrel and $3.81 to $6.61 per Mcf in the six months ended June 30, 2013 and at prices ranging from $82.87 to $106.49 per barrel and $3.64 to $5.82 per Mcf in the six months ended June 30, 2012. In our Cimarrona property in Colombia, we sold oil at prices ranging from $94.73 to $112.13 per barrel during the six months ended June 30, 2013 compared to $99.80 to $119.00 during the six months ended June 30, 2012. We began to sell natural gas liquids in the second quarter of 2013, at prices ranging from $25.91 to $28.87 per barrel. The Colombian Peso to Dollar Exchange Rate averaged approximately 1,829 and 1,793 during the six months ended June 30, 2013 and 2012, respectively. The Colombian Peso to Dollar Exchange Rate was 1,928 and 1,795 at June 30, 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 six months ended June 30, 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 June 30, 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.

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: