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OEDV > SEC Filings for OEDV > Form 10-K on 2-Apr-2013All Recent SEC Filings

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Form 10-K for OSAGE EXPLORATION & DEVELOPMENT INC


2-Apr-2013

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation.

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 the Purchase Agreement with Sunstone pursuant to which we acquired from Sunstone 100% of the membership interests in Cimarrona
LLC. Cimarrona LLC is the owner of 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 twenty-one 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, but not the pipeline, is subject to the Association Contract whereby we pay Ecopetrol royalties of 20% of the oil produced. The royalty 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 indicates the partners in the Association Contract received a 200% reimbursement plus recovery 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 reduce the cash flows generated by the field 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 Cimarrona 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 present 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 in Oklahoma since the 1940s. Beginning in 2007, the application of 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 shall be allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson will be the operator of all wells in the Nemaha Ridge prospect. 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 has provided its management and consultants an overriding royalty interest ("ORRI") equal to the difference between the NRI and 78%. At December 31, 2012, the Company had 7,797 net acres (47,627 gross) leased in Logan County. In December 2011, the Company participated in drilling its first well in Logan County and at December 31, 2012 the Company had participated in drilling eight wells, five of which achieved production and revenues in 2012. Also as of December 31, 2012, the Company had 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 December 31, 2012, the Company had 3,446 net acres (4,925 gross) leased in Pawnee County. As of December 31, 2012, none of these leases have been assigned to B&W.

In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the oily Woodford Shale formation. The oily Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The oily Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At December 31, 2012, we had 4,253 net (9,509 gross) acres leased in Coal County.

At December 31, 2012, we have leased 62,061 gross (15,496 net) acres across three counties in Oklahoma as follows:

                                                   Osage
                                      Gross         Net
                            Logan      47,627        7,797
                            Pawnee      4,925        3,446
                            Coal        9,509        4,253
                                       62,061       15,496

The Company has an accumulated deficit of $8,074,786 and a working capital deficit of $643,843 at December 31, 2012. In 2011, we recognized a one-time gain of $3,109,646 from assignment of leases in Logan County, Oklahoma. Our operating plans require additional funds that may take the form of debt or equity financings. There can be no assurance that any additional funds will be available. Our ability to continue as a going concern is in substantial doubt and is dependent upon achieving a profitable level of operations and obtaining additional financing.

We anticipate we will need to raise at least $10,000,000 to sustain operations over the next 12 months, with the majority of the capital being used to drill additional wells in Logan County, Oklahoma. At present, the revenues generated from the Cimarrona and Logan County properties are only sufficient to cover field operating expenses and a portion of our overhead. We have 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 capital and/or obtaining financing. There is no assurance we will successfully accomplish these steps and it is uncertain we will achieve profitable operations and/or obtain additional financing. There can be no assurance any additional financings will be available to us on satisfactory terms and conditions, if 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.

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") (see Note 6 - Debt, in the accompanying consolidated financial statements). We anticipate that we will draw down the full $10,000,000 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. We are currently in negotiations with Apollo with respect to an expanded senior secured facility.

Results of Operations

Year ended December 31, 2012 compared to year ended December 31, 2011

                                 2012                             2011                      Increase/(Decrease)
                       Amount         Percentage        Amount         Percentage         Amount         Percentage

Oil Sales            $ 3,973,666             64.9 %   $ 1,920,834             54.6 %   $  2,052,832            106.9 %
Pipeline Sales         1,912,941             31.3 %     1,594,889             45.4 %        318,052             19.9 %
Natural Gas Sales        233,417              3.8 %             -              0.0 %        233,417              N/A
Total Revenues       $ 6,120,024            100.0 %   $ 3,515,723            100.0 %   $  2,604,301             74.1 %

Oil Sales

Oil sales were $3,973,666, in 2012, an increase of $2,052,832, or 106.9%, compared to $1,920,834 in 2011. The increase in oil sales is mostly due to our new wells in Logan County, Oklahoma. In the United States, we sold 22,146 barrels ("BBLs") in 2012 at an average gross price of $94.13 per barrel, compared to 797 BBLs in 2011 at an average price of $88.60 per barrel. In Colombia, we sold 19,000 barrels in both 2012 and 2011, at an average price per barrel of $105.98 in 2012 compared to $101.86 in 2011.

Pipeline Sales

Pipeline sales were $1,912,941 in 2012, an increase of $318,052, or 19.9%, compared to $1,594,889 in 2011. In 2011, the pipeline transported 10.13 million BBLs (our share was approximately 0.95 million BBLs) compared to 9.17 million BBls (our share was approximately 0.86 million BBLs) in 2011. Revenue per barrel transported was $2.01 in the year ended December 31, 2012 compared to $1.81 in the year ended December 31, 2011.

Natural Gas Sales

Natural gas sales were $233,417 for the year ended December 31, 2012 compared to $0 for the year ended December 31, 2011. All of our natural gas sales are from the well production in Logan County, Oklahoma. Natural gas production is measured in a 1,000 cubic foot unit referred to as a "Mcf."

Total Revenues

Total revenues were $6,120,024, an increase of $2,604,301 or 74.1% for the year ended December 31, 2012 compared to $3,515,723 for the year ended December 31, 2011. Oil sales accounted for 64.9% and 54.6% of total revenues in the 2012 and 2011 periods, respectively.

Production



                                  2012                     2011               Increase/(Decrease)
                            Net         % of         Net         % of
Oil Production:           Barrels       Total      Barrels       Total       Barrels           %
United States               22,057        55.6 %        797         4.2 %       21,260       2,667.5 %
Colombia                    17,627        44.4 %     18,365        95.8 %         (738 )        (3.8 %)
Total                       39,684       100.0 %     19,162       100.0 %       20,522         107.1 %

                                         % of                     % of
Natural Gas Production:      Mcf         Total        Mcf         Total          Mcf            %
United States               62,131       100.0 %          -         0.0 %       62,131             -

Oil production, net of royalties, was 39,683 BBLs, an increase of 20,522 BBLs, or 107.1% for the year ended December 31, 2012 compared to 19,162 BBLs for the year ended December 31, 2011, due to production increases in the U.S. U.S. production accounted for 55.6% and 4.2% of total production for the years ended December 31, 2012 and 2011, respectively.

Natural gas production was 62,131 Mcf for the year ended December 31, 2012. Gas production began in the first quarter of 2012 in our Logan County properties, and there was no production of natural gas during 2011.

Operating Costs and Expenses



                                                    2012                              2011                        Increase/(Decrease)
                                                         Percent of                        Percent of
                                          Amount          Revenues          Amount          Revenues          Amount         Percentage
Operating Expenses
Operating costs                         $ 1,812,725              29.6 %   $ 1,068,087              30.4 %   $   744,638             69.7 %
General & administrative expenses         2,716,233              44.4 %     1,954,286              55.6 %   $   761,947             39.0 %
Equity tax                                  131,186               2.1 %       450,064              12.8 %   $  (318,878 )          (70.9 %)
Depreciation, depletion and accretion       568,777               9.3 %       429,689              12.2 %   $   139,088             32.4 %
Loss on disposal of fixed assets             21,599               0.4 %             -               0.0 %   $    21,599              n/a
Total Operating Costs and Expenses      $ 5,250,520              85.8 %   $ 3,902,126             111.0 %   $ 1,348,394             34.6 %

Operating Expenses

Our operating expenses in 2012 were $1,812,725, an increase of $744,638, or 69.7% compared to $1,086,087 in 2011, due primarily to an increase in operating costs in Logan County, Oklahoma. Operating expenses as a percentage of total revenues declined to 29.6% in 2012 from 30.4% in 2011, 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. production, to 55.6% in 2012 from 4.2% in 2011 as average Production Cost/BOE in the U.S. for 2012 was $7.26 compared to the average cost in Colombia of $41.04. Our average total Production Cost/BOE for the year ended December 31, 2012 was $19.45.

General and Administrative Expenses

General and administrative expenses in 2012 were $2,716,233, an increase of $761,947, or 39.0% compared to $1,954,286 in 2011. Stock-based compensation expense was $896,694 and $267,600 in 2012 and 2011, respectively. The increase in stock-based compensation expense of $629,094 for the year ended December 31, 2012 related both to an increase in stock granted and to an increase in the stock price at the time of issuance. The majority of shares were immediately vested. The remaining increase of $132,853 is due primarily to a $42,882 increase in legal and professional services, a $29,310 increase in insurance, a $13,125 increase in office expenses and a $8,914 increase in computer expenses. General and administrative expenses as a percentage of total revenues decreased to 44.4% in 2012 from 55.6% in 2011, due to the 74.1% increase in revenues.

Equity Tax

Division de Impuestosy Actuanas Nacionales ("DIAN"), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. The equity tax for 2011 is comprised of both current equity taxes as well as taxes that were assessed by DIAN on Cimarrona's operations in 2001 and 2003 prior to its ownership by us.

                                                       Increase/(Decrease)
                        2012          2011           Amount         Percentage
Current Equity Tax    $ 131,186     $ 127,776     $      3,410              2.7 %
2001/2003 Tax Years           -       322,288         (322,288 )            n/a
Total Equity Tax      $ 131,186     $ 450,064     $    318,878            (70.9 %)

In 2010, the Company was notified by DIAN that it owed $883,742 in equity taxes relating to 2001 and 2003 equity tax years. To compute the equity 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 to correspond to the amount DIAN indicated we owed for the 2003 tax year. In January 2013 we concluded negotiations with DIAN with respect to the ultimate liability for the 2003 tax year. DIAN waived certain penalties and interest in the amount of $548,092. We paid the agreed final liability to DIAN in January 2013, using the proceeds of an unsecured Colombian banking facility and are awaiting confirmation that the 2003 tax year is fully settled. We will recognize the benefit upon receipt of such confirmation.

Depreciation, depletion and accretion

Depreciation, depletion and accretion were $568,777 for the year ended December 31, 2012 and $429,689 for the year ended December 31, 2011, an increase of $139,088 or 32.4%. Our depletion expense will increase in the future to the extent we are successful in our well production in Oklahoma.

Income / (Loss) from Operations

Income from operations was $869,504 in 2012 compared to a loss from operations of $386,403 in 2011. The improvement in operating results of $1,255,907 was due to the increase in revenues of $2,604,301 for the year ended December 31, 2012 compared to the year ended December 31, 2011, partially offset by the $1,348,394 increase in operating costs and expenses during the same period.

Interest Expense

Interest expense was $1,390,277 for the year ended December 31, 2012 compared to $137,204 for the year ended December 31, 2011, an increase of $1,253,073. The increase in interest expense during the 2012 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. Interest expense for the 2011 period is for the Blackrock Promissory Note issued in January 2011 and repaid in May 2011, and the Hoffman Note issued in April 2011 and repaid in May 2011. In the year ended December 31, 2012, cash interest expense amounted to $538,889. The remaining non-cash interest expense of $851,388 consisted primarily of deferred financing fees of $734,976 and debt discount amortization of $114,596.

Gain from Assignment of Leases

We recognized a gain from assignment of leases of $0 in 2012 compared to $3,109,646 in 2011. The 2011 gain related to the assignment of leases in the Nemaha Ridge prospect in Logan County, Oklahoma pursuant to the Participation Agreement.

Provision for Income Taxes

Provision for income taxes was $0 in 2012 compared to $58,893 in 2011. Most of the provision for income taxes in 2011 relates to the federal alternative minimum tax resulting from the gain on assignment of leases.

Net (Loss) / Income

Net loss was $516,706 in 2012 compared to a net income of $2,535,599 in 2011. The improvement in operating income in 2012 of $1,255,907 compared to 2011 was offset by the $1,253,073 increase in interest expense in 2012 and the $3,109,646 gain from assignment of leases in 2011.

Foreign Currency Translation

Foreign currency translation loss was $21,460 in 2012 compared to a gain of $7,276 in 2011. The Colombian Peso to Dollar Exchange Rate averaged 1,797 and 1,848 in 2012 and 2011, respectively. The Colombian Peso to Dollar Exchange Rate was 1,805 and 1,935 at December 31, 2012 and December 31, 2011, respectively.

Comprehensive Income/(Loss)

Comprehensive loss was $538,166 for the year ended December 31, 2012 compared to a comprehensive income of $2,542,875 for the year ended December 31, 2011. Comprehensive income decreased by $3,081,041 due to the $3,052,305 decrease in net income to a loss in the 2012 period compared to the 2011 period and the $28,736 decrease in foreign currency translation to a loss in the 2012 period compared to a gain in the 2011 period.

Income/(Loss) per Share

Basic and diluted loss per share was $0.01 in 2012 compared to an income per share of $0.05 in 2011.

Liquidity and Capital Resources

We had a working capital deficit of $643,843 at December 31, 2012, compared to working capital of $1,061,190 at December 31, 2011. Working capital at December 31, 2012 consisted primarily of deferred financing costs of $2,924,472, $486,205 of cash and equivalents and $486,112 of accounts receivable offset by $3,000,000 of notes payable, $1,328,652 of accrued expenses and $236,977 of accounts payable. Working capital at December 31, 2011 consisted primarily of $1,904,023 of cash and equivalents and $358,344 of accounts receivable offset by $876,545 of accrued expenses and $323,699 of accounts payable.

Net cash provided by operating activities was $1,834,606 in 2012 compared to $57,649 in 2011. The major components of net cash provided by operating activities in 2012 were the $568,777 provision for depreciation, depletion and the amortization of deferred financing costs of $734,796, shares issued for services of $448,583 and warrants issued for services of $448,111, offset by the $516,706 net loss and the increase in accounts receivable of $363,548. The major components of net cash provided by operating activities in 2011 were the $2,535,599 net income and the $429,689 provision for depreciation and depletion, offset by the $3,109,646 gain on assignment of leases.

Net cash used by investing activities was $7,970,569 in 2012 compared to net cash provided by investing activities of $1,559,853 in 2011. Net cash used by investing activities in 2012 consisted primarily of $12,781,375 investment in oil and gas properties, partially offset by $4,686,610 net proceeds from assignment of leases. Net cash provided by investing activities in 2011 consisted primarily of $5,339,797 net proceeds from assignment of leases offset by $3,754,863 investment in oil and gas properties.

Net cash provided by financing activities was $4,831,308 and $0 in 2012 and 2011, respectively. Net cash provided in 2012 consisted primarily of $5,500,000 of borrowing on secured promissory notes, partially offset by payment of $670,692 of deferred financing costs. 2011 consisted of $700,000 of borrowing on promissory notes offset by $700,000 of repayment of those promissory notes.

We conduct no product research and development. Any expected purchase of significant equipment is directly related to drilling operations and the completion of successful wells.

Slawson is the operator in our Logan County, Oklahoma properties. Pacific Rubiales, which owns 90.6% of the Guaduas field, is the operator of Cimarrona.

We are responsible for any contamination of land we own or lease. However, we carry pollution liability insurance policies, which may limit some potential contamination liabilities as well as claims for reimbursement from third parties.

Effect of Changes in Prices

Changes in prices during the past few years have been a significant factor in the oil and gas industry. The price received for the oil produced by us fluctuated significantly during the last year. Changes in the price that we receive for our oil and gas is set by market forces beyond our control as well as governmental intervention. The volatility and uncertainty in oil and gas prices have made it more difficult for a company like us to increase our oil and gas asset base and become a significant participant in the oil and gas industry. We currently sell the majority our oil and gas production to Slawson in the United States and to Hocol in Colombia. However, in the event these customers discontinued oil and gas purchases, we believe we can replace them with other customers which would purchase the oil and gas at terms standard in the industry.

Critical Accounting Policies and Estimates

Management's Discussion and Analysis of Financial Condition and Results of Operations discusses our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an on-going basis, management evaluates our estimates and judgments, including those related to revenue recognition, recovery of oil and gas reserves, financing operations, and contingencies and litigation.

Oil and Gas Properties

We follow the "successful efforts" method of accounting for our oil and gas exploration and development activities, as set forth in the FASB ASC Topic 932. Under this method, we initially capitalize expenditures for oil and gas property acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful. The carrying value of all undeveloped . . .

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