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 Oklahomalimited liability company (" Cimarrona LLC"). Cimarrona LLCowns a 9.4% interest in certain oil and gas assets in the Guaduasfield, 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 Valleyin Colombiaas 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 Guaduasfield. 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 LLCto Raven Pipeline Company, LLC("Raven"), pursuant to a Membership Interest Purchase Agreement (the "Agreement") dated September 30, 2013by and between the Company and Raven. Accordingly, the Company will not recognize any revenues or expenses for Cimarrona LLCfrom October 1, 2013. The sales price consisted of cash of $6,800,000, less settlement of debt of Cimarrona LLCof approximately $250,000. Of the net sales price, $250,000will be held in escrow for 12 months to secure any post-closing purchase price adjustments and any indemnity obligations of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with respect to the pipeline is not adjusted prior to March 31, 2014, then Raven is obligated to pay the Company an additional $1,000,000in 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, Oklahomatargeting the Mississippian formation. The Mississippian formation is located on the Anadarko Shelf in northern Oklahomaand 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 Shaleformations. 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 Ridgeprospect in Logan County, Oklahomafor $4,875,000. In addition, the Parties carried Osagefor 7.5% of the cost of the first three horizontal Mississippian wells, which means that for the first three horizontal Mississippian wells, the Company provided up to 17.5% of the total well costs. After the first three wells, the Company is responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty payments, is allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson was the operator of all wells in the Nemaha Ridgeprospect 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, Osageand Slawson entered into an agreement (the "Partition Agreement") which amended Participation Agreement related to certain lands located within the Nemaha Ridgein 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 Groupagreed 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 Projectwithin certain sections to Osageand Osageagreed 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 Projectwithin 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 Projectexcept 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, Osagehas become the project operator on a majority of its acreage in the Nemaha Ridge Project. As of March 31, 2014, Osagewas allocated approximately 5,457 net acres (11,228 gross) in thirty-one sections, and remains joint-venture partners with the Slawson in approximately 4,192 net acres (26,167 gross) across forty-one sections. 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 Countyprospect 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 $200,000of 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 March 31, 2014, the Company had 4,190 net acres (5,085 gross) leased in Pawnee County. As of March 31, 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 Shaleformation. The Woodford Shaleformation is located mainly in southeastern Oklahomain the Arkoma Basin. The Woodfordshale 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 Woodfordin recent years with much success. At March 31, 2014, we had 4,253 net (9,509 gross) acres leased in Coal County.
Gross Osage Net Logan (non operated) 26,167 4,192 Logan 11,228 5,457 Coal 9,509 4,253 Pawnee 5,085 4,190 51,989 18,092
We have accumulated deficits of
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 $10,000,000senior secured note purchase agreement with Apollo Investment Corporation. On April 5, 2013we amended this agreement, increasing the facility to $20,000,000and on April 3, 2014we 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 Liborplus 15% to Liborplus 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. As of March 31, 2014, 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 under the senior secured note purchase agreement. The Company and Apollo are presently in discussions with respect to covenant modifications. Until such discussions are concluded, the existing covenants are in effect and, accordingly, the Company has classified the borrowings under the Note Purchase Agreement as short term in the accompanying consolidated balance sheets. In February 2014, the Company initiated a private placement, pursuant to Securities Purchase Agreements between Osageand certain purchasers, with aggregate gross proceeds of approximately $6.4 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 $1.80per share, was $0.90. The warrants have a term of five years. The placement agent receives placement fees of 8%, in cash or warrants or a combination thereof at their election. 4 The Company's operating plans require additional funds which may take the form of debt or equity financings. The Company's ability to continue as a going concern is in substantial doubt and is dependent upon achieving profitable operations and obtaining additional financing. There is no assurance additional funds will be available on acceptable terms or at all. In the event we are unable to continue as a going concern, we may elect or be required to seek protection from our creditors by filing a voluntary petition in bankruptcy or may be subject to an involuntary petition in bankruptcy. Results of Operations
Three Months ended
Our total revenues for the three months ended
March 31, 2014and 2013 comprised the following: 2014 2013 Change Amount Percentage Amount Percentage Amount Percentage Revenues Oil sales $ 2,132,81780.9 % $ 1,087,83989.8 % $ 1,044,97896.1 %
Natural gas sales 504,598 19.1 % 124,033 10.2 % 380,565 306.8 % Total revenues
$ 2,637,415100.0 % $ 1,211,872
$ 1,425,543117.6 % Oil Sales Oil Sales were $2,132,817, an increase of $1,044,978, or 96.1%, for the three months ended March 31, 2014compared to $1,087,839for the three months ended March 31, 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 21,427 barrels ("BBLs") at an average price of $97.16in the 2014 period, compared to 12,115 BBLs at an average price of $89.79in 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 $451,784for the three months ended March 31, 2014compared to $124,033for the three months ended March 31, 2013, an increase of $327,751, or 264.2%. Natural gas liquid sales were $52,814for the three months ended March 31, 2014and there were no natural gas liquid sales in the three months ended March 31, 2013. All of our natural gas and natural gas liquid sales are from the well production in Logan County, Oklahoma. Total revenues were $2,637,415, an increase of $1,425,543or 117.6% for the three months ended March 31, 2014compared to $1,211,872for the three months ended March 31, 2013. Oil sales accounted for 80.9% and 89.8% of total revenues in the 2014 and 2013 periods, respectively. 5 Production For the three months ended March 31, 2014and 2013, our production was as follows: 2014 2013 Increase/(Decrease) Oil Production: Net Barrels % of Total Net Barrels % of Total Barrels % United States 22,330 100.0 % 12,160 100.0 % 10,170 83.6 % Natural Gas Production: Net Mcf % of Total Net Mcf % of Total Mcf % United States 77,627 100.0 % 26,568 100.0 % 51,059 192.2 % Natural Gas Liquid Production: Net Barrels % of Total Net Barrels % of Total Barrels % United States 1,796 100 % - n/a 1,796 n/a Oil production, net of royalties, was 22,330 BBLs, an increase of 10,170 BBLs, or 83.6% for the three months ended March 31, 2014compared to 12,160 BBLs for the three months ended March 31, 2013, due to production increases as a result of new wells coming online.
Natural gas production was 77,627 thousand cubic feet ("Mcf") for the three months ended
March 31, 2014, an increase of 51,059 Mcf, or 192.2% over the production of 26,568 Mcf in the 2013 period. Natural gas liquid production was 1,796 BBLs in the three months ended March 31, 2014and there was no natural gas liquid production in the prior year period. Gas production began in the first quarter of 2012 in our Logan Countyproperties. 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
March 31, 2014and 2013, our operating costs and expenses were as follows: 2014 2013 Change Percent of Percent of Amount Sales Amount Sales Amount Percentage Operating Expenses Operating expenses $ 473,14217.9 % $ 182,37115.0 % $ 290,771159.4 % General & administrative expenses 843,952 32.0 % 843,710 69.6 % 242 0.0 % Depreciation, depletion and accretion 999,899 37.9 % 270,485 22.3 % 729,414 269.7 % Total operating expenses $ 2,316,99387.9 % $ 1,296,566
$ 1,020,42778.7 % Operating income $ 320,42212.1 % $ (84,694 )-7.0 % $ 405,116-478.3 % Operating Costs
Our operating costs were
$473,142for the three months ended March 31, 2014compared to $182,371for the three months ended March 31, 2013, due to an increase in operating costs in the U.S. as a result of having 42 wells in production in Logan Countyat March 31, 2014. Operating costs as a percentage of total revenues increased to 17.9% in the 2014 period from 15.0% in 2013 period, as the percentage increase in revenues was less 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 March 31, 2014was $12.77compared to an average total Production Cost/BOE of $10.99for the three months ended March 31, 2013.
General and Administrative Expenses
General and administrative expenses were
$843,952for the three months ended March 31, 2014, essentially flat compared to $843,710for the three months ended March 31, 2013. As a percent of total revenues, general and administrative expenses decreased to 32.0% in the 2014 period from 69.6% in the 2013 period. Stock based compensation for the three months ended March 31, 2014was $109,000, compared to $378,750in the three months ended March 31, 2013. The increase of $269,992in other general and administrative expenses was primarily due to increased salary, legal and professional and insurance expenses. 6
Depreciation, Depletion and Accretion
Depreciation, depletion and accretion were
$999,899for the three months ended March 31, 2014and $270,485for the three months ended March 31, 2014, an increase of $729,414or 269.7%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma. Operating Income (Loss) Operating income was $320,422for the three months ended March 31, 2014compared to an operating loss of $84,694for the three months ended March 31, 2014. The improvement in operating income is as a result of revenue growth of 117.6% exceeding the 78.7% increase in total operating expenses. Interest Expense Interest expense was $1,210,560for the three months ended March 31, 2014compared to $766,506for the three months ended March 31, 2013, an increase of $444,054. The increase in interest expense during the 2014 period was primarily due to greater amounts outstanding under our credit facilities. In the three months ended March 31, 2014, cash interest expense amounted to $862,577. The remaining non-cash interest expense of $347,983represented amortization of deferred financing fees. In the three months ended March 31, 2013, cash interest expense amounted to $408,779. The remaining non-cash interest expense of $357,727consisted primarily of deferred financing fees of $314,462and debt discount amortization of $43,265. Oil and Gas Derivatives Oil and gas derivatives reflected an unrealized loss of $68,058for the three months ended March 31, 2014as a result of marking open financial derivative instruments to market as of March 31, 2014and losses realized on financial derivative instruments settled of $47,669during the three months then ended. There were no open financial derivative instruments as of March 31, 2013.
Provision for Income Taxes
Provision for income taxes was zero for the three months ended
March 31, 2014and 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
$935,127for the three months ended March 31, 2014compared to a loss of $851,083for the three months ended March 31, 2013. The $405,116increase in operating income was more than offset by the $444,054increase in interest expense and the $115,727loss on oil and gas derivatives in the three months ended March 31, 2014compared to the prior
Income from Discontinued Operations Net of Income Taxes
Income from discontinued operations net of income taxes was
Net Income (Loss)
Net loss was
$935,127in the three months ended March 31, 2014compared to a net loss of $73,425in 2013. The increase in loss from continuing operations of $84,044and the reduction of $777,658in net income from discontinued operations represent the drivers of the $861,702increase in net loss.
Foreign Currency Translation Adjustment Attributable to Discontinued Operations
There was no foreign currency gain or loss in the three months ended
Comprehensive Income (Loss) Comprehensive loss was
$935,127for the three months ended March 31, 2014compared to a comprehensive loss of $49,862for the three months ended March 31, 2013. The increase in net loss of $861,702to $935,127in 2014 was the primary contributor, along with the foreign currency translation gain of $23,563in
the prior year period. 7 Income (Loss) per Share Basic and diluted loss per share from continuing operations was
$0.02the three months ended March 31, 2014compared to a loss per share of $0.02in the prior year period. There was no income from discontinued operations in the three months ended March 31, 2014, compared to basic and diluted income from discontinued of $0.02per share in the prior year period.
Liquidity and Capital Resources
Net cash provided by operating activities totaled
$3,655,826for the three months ended March 31, 2014, compared to net cash provided of $1,918,817for the three months ended March 31, 2013. The major components of net cash provided by operating activities for the three months ended March 31, 2014included non-cash activities which consisted of provision for depreciation, depletion and amortization of $999,699, amortization of deferred financing costs of $347,983, shares issued for services of $109,000and unrealized losses on derivative contracts of $68,058. Other significant components included the $1,520,507increase in accounts payable due primarily to our Oklahomaoperations related to well production along with a reduction in accounts receivable of $388,618. Net cash provided by operating activities for the three months ended March 31, 2013totaled $1,918,817. The major components of the net cash provided by operating activities in 2013 were an increase in accounts payable of $1,912,332, shares issued for services of $378,750, provision for depreciation, depletion and accretion of $329,237and amortization of deferred financing costs of $314,462, partially offset by a decrease in accrued expenses of $609,665and an increase in accounts receivable of $428,976. Net cash used in investing activities totaled $3,892,720for the three months ended March 31, 2014and consisted primarily of investments in oil and gas wells of $3,955,953. Net cash used investing activities in 2013 totaled $5,750,031and consisted primarily of $5,706,254investment in oil and gas properties, along with an increase of $63,623in restricted cash.
Net cash provided by financing activities totaled
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,
Stephensand 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 countyproperties, we sold oil and gas at prices ranging from $92.82to $100.38per barrel and $3.81to $6.89per Mcf in the three months ended March 31, 2014and at prices ranging from $86.49to $93.75per barrel and $3.51to $6.52per Mcf in the three months ended March 31, 2013. We began to sell natural gas liquids in the second quarter of 2013 and we sold natural gas liquids in our Logan countyproperties at prices ranging from $27.00to $35.33in the three months ended March 31, 2014.
We have exposure to changes in interest rates as our Apollo debt facility is tied to the
Oil and Gas PropertiesWe 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 three months ended March 31, 2014or 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. 8 This calculation is done on a field-by-field basis. As of March 31, 2014and 2013 our oil production operations were conducted in the U.S. The cost of unevaluated properties not being amortized, to the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized cost. The cost of any impaired property is transferred to the balance of O&G properties being depleted. The costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which we intend to commence such activities in the future. We will begin to amortize these costs when proved reserves are established or impairment is determined. In accordance with FASB ASC Topic 410 ("ASC 410"), "Accounting for Asset Retirement Obligations," we record a liability for any legal retirement obligations on our O&G properties. The asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate the producing properties at the end of their productive lives, in accordance with State laws, as well as the estimated costs associated with the reclamation of the property surrounding. The Company determines the asset retirement obligations by calculating the present value of estimated cash flows related to the liability. The asset retirement obligations are recorded as a liability at the estimated present value as of the asset's inception, with an offsetting increase to producing properties. Periodic accretion of the discount related to the estimated liability is recorded as an expense in the statement of operations. The estimated liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells, and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations. Revisions to the asset retirement obligations are recorded with an offsetting change to producing properties, resulting in prospective changes to depletion and depreciation expense and accretion of the discount. Because of the subjectivity of assumptions and the relatively long lives of most of the wells, the costs to ultimately retire the Company's wells may vary significantly from prior estimates. Revenue Recognition We recognize revenue upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received by the customer, (ii) an invoice is generated which evidences an arrangement between the customer and us, (iii) a fixed sales price has been included in such invoice and (iv) collection from such customer is probable.
Off-Balance Sheet Arrangements
Our Company has not entered into any transaction, agreement or other contractual arrangement with an entity unconsolidated with us, except as disclosed in our financial statements, under which we have:
? an obligation under a guarantee contract,
? a retained or contingent interest in assets transferred to the unconsolidated
entity or similar arrangement that serves as credit, liquidity or market risk
support to such entity for such assets,
? any obligation including a contingent obligation, under a contract that would
be accounted for as a derivative instrument, or
? any obligation, including a contingent obligation, arising out of a variable
interest in an unconsolidated entity that is held by us and material to us
where such entity provides financing, liquidity, market risk or credit risk
support to, or engages in leasing, hedging or research and development services