Thanks, Form 10-Q for OSAGE EXPLORATION & DEVELOPMENT INC
12-Nov-2013
Quarterly Report
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. The property and the pipeline are both operated by Pacific, which owns 90.6% of the Guaduas field. Pipeline revenues generated from the Cimarrona property primarily relate to transportation costs charged to third party oil producers, including Pacific.
On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company, LLC ("Raven"), pursuant to a Membership Interest Purchase Agreement (the "Agreement") dated September 30, 2013 by and between the Company and Raven. Accordingly, the Company will not recognize any revenues or expenses for Cimarrona LLC from October 1, 2013. The sales price consisted of cash of $6,800,000, less settlement of debt of Cimarrona LLC of approximately $250,000. Of the net sales price, $250,000 will be held in escrow for 12 months to secure any post-Closing purchase price adjustments and any indemnity obligations of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with respect to the pipeline is not adjusted prior to March 31, 2014, then Raven will pay the Company an additional $1,000,000 in cash within five business days of that date.
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 September 30, 2013, the Company had 8,271 net acres (48,368 gross) leased in Logan County. In December 2011, the Company began drilling its first well in Logan County and at September 30, 2013 the Company had participated, or was participating, in drilling 36 wells, 29 of which had achieved production and revenues by September 30, 2013. As of September 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 September 30, 2013, the Company had 4,190 net acres (5,085 gross) leased in Pawnee County. As of September 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 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 September 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 September 30, 2013, we had 465 net (2,240 gross) acres leased in Garfield County.
At September 30, 2013, we had leased an aggregate of 17,179 net (65,202 gross) acres across four counties in Oklahoma as follows:
Gross Osage Net
Logan 48,368 8,271
Garfield 2,240 465
Pawnee 5,085 4,190
Coal 9,509 4,253
65,202 17,179
We have accumulated deficits of $8,316,321 (unaudited) at September 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 $18,493,494 and $643,843 as of September 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) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (b) controlling overhead and expenses, (c) selling our Colombian operations owned by our wholly owned subsidiary, Cimarrona, LLC and (d) selling certain assets and 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 September 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 September 30, 2013. The amendment also provided for an immediate draw down 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, 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 did not complete either one of the aforementioned transactions, the Company would have been 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. On October 7, 2013 the Company completed the sale of its membership interests in Cimarrona LLC. This sale satisfied the requirements of the amendment and the Company is thus not obligated to issue additional Warrants to Apollo. 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 September 30, 2013 compared to Three Months ended September 30, 2012
Our total revenues for the three months ended September 30, 2013 and 2012 comprised the following:
2013 2012 Change
Amount Percentage Amount Percentage Amount Percentage
Revenues
Oil sales $ 2,916,342 79.6 % $ 1 ,262,050 68.0 % $ 1 ,654,292 131.1 %
Pipeline sales 617,145 16.9 % 5 08,505 27.4 % 1 08,640 21.4 %
Natural gas sales 128,134 3.5 % 84,572 4.6 % 4 3,562 51.5 %
Total revenues $ 3,661,621 100.0 % $ 1 ,855,127 100.0 % $ 1 ,806,494 97.4 %
Oil Sales
Oil Sales were $2,916,342, an increase of $1,654,292, or 131.1%, for the three months ended September 30, 2013 compared to $1,262,050 for the three months ended September 30, 2012. Oil sales increased due to an increase in the number of barrels sold and an increase in the average price per barrel. In the United States ("US"), we sold 24,322 barrels ("BBLs") at an average price of $105.03 in the 2013 period, compared to 7,439 BBLs at an average price of $96.64 in the 2012 period. In Colombia, we sold 4,000 BBLs at an average price of $100.57 in the 2013 period compared to 6,000 BBLs at an average price of $100.54 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 $617,145, an increase of $108,640, or 21.4% for the three months ended September 30, 2013 compared to $508,505 for the three months ended September 30, 2012, primarily due to an increase in the number of barrels transported. The number of barrels transported was 3.27 million BBLS (our share was approximately 307,000) and 2.69 million BBLs (our share was approximately 253,000) in the three months ended September 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 $128,134 for the three months ended September 30, 2013 compared to $84,572 for the three months ended September 30, 2012, an increase of $43,562, or 51.5%. All of our natural gas sales are from the well production in Logan County, Oklahoma.
Total revenues were $3,661,261, an increase of $1,806,494, or 97.4% for the three months ended September 30, 2013 compared to $1,855,127 for the three months ended September 30, 2012. Oil sales accounted for 79.6% and 68.0% of total revenues in the 2013 and 2012 periods, respectively.
Production
For the three months ended September 30, 2013 and 2012, our production was as
follows:
2013 2012 Increase/(Decrease)
Oil Production: Net Barrels % of Total Net Barrels % of Total Barrels %
United States 24,752 87.9 % 7,442 62.7 % 17,310 232.6 %
Colombia 3,397 12.1 % 4,435 37.3 % (1,038 ) -23.4 %
Total 28,149 100.0 % 11,877 100.0 % 16,272 137.0 %
Natural Gas Production: Net Mcf % of Total Net Mcf % of Total Mcf %
United States 30,870 100.0 % 19,452 100.0 % 11,418 58.7 %
Natural Gas Liquid
Production: Net Barrels % of Total Net Barrels % of Total Barrels %
United States 293 100.0 % - n/a 293 n/a
Oil production, net of royalties, was 28,149 BBLs, an increase of 16,272 BBLs, or 137.0% for the three months ended September 30, 2013 compared to 11,877 BBLs for the three months ended September 30, 2012, primarily due to production increases in the U.S. U.S. production accounted for 87.9% and 62.7% of total production for the three months ended September 30, 2013 and 2012, respectively.
Natural gas production was 30,870 thousand cubic feet ("Mcf") for the three months ended September 30, 2013, an increase of 11,418 Mcf, or 58.7% over the production of 19,452 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 293 BBLs in the three months ended September 30, 2013.
Operating Costs and Expenses
For the three months ended September 30, 2013 and 2012, our operating costs and
expenses were as follows:
2013 2012 Change
Percent of Percent of
Amount Sales Amount Sales Amount Percentage
Operating Expenses
Operating $ 7 76,184 21.2 % $ 407,073 21.9 % $ 369,111 90.7 %
General &
administrative 5 55,648 15.2 % 447,649 24.1 % 107,999 24.1 %
Equity tax 30,970 0.8 % 3 2,878 1.8 % (1,908 ) -5.8 %
Depreciation,
depletion and
accretion 7 48,061 20.4 % 226,682 12.2 % 521,379 230.0 %
Total operating
expenses $ 2 ,110,863 57.6 % $ 1 ,114,282 60.1 % $ 996,581 89.4 %
Operating income $ 1 ,550,758 42.4 % $ 740,845 39.9 % $ 809,913 109.3 %
Operating Costs
Our operating costs were $776,184 for the three months ended September 30, 2013 compared to $407,073 for the three months ended September 30, 2012, due primarily to an increase in operating costs in the U.S. as a result of having 29 wells in production in Logan County at September 30, 2013. Operating costs as a percentage of total revenues reduced to 21.2% in the 2013 period from 21.9% 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 87.9% in the 2013 period from 62.7% 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 September 30, 2013 was $14.94 compared to the average cost in Colombia of $33.91. Our average total Production Cost/BOE for the three months ended September 30, 2013 was $20.40.
General and Administrative Expenses
General and administrative expenses were $555,648 for the three months ended September 30, 2013, an increase of $107,999 or 24.1%, compared to $447,649 for the three months ended September 30, 2012. As a percent of total revenues, general and administrative expenses decreased to 15.2% in the 2013 period from 24.1% in the 2012 period. The increase of $107,999 in administrative expenses was primarily due to increased salary, legal and professional and insurance expenses. Stock based compensation for the three months ended September 30, 2013 was $14,750, compared to $13,800 in the three months ended September 30, 2012.
Equity Tax
Current equity tax was $30,970 for the three months ended September 30, 2013 and $32,878 for the three months ended September 30, 2012. Division de Impuestos y Actuanas Nacionales ("DIAN"), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona.
Depreciation, depletion and accretion
Depreciation, depletion and accretion were $748,061 for the three months ended September 30, 2013 and $226,682 for the three months ended September 30, 2012, an increase of $521,379 or 230.0%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.
Operating Income
Operating income was $1,550,758 for the three months ended September 30, 2013 compared to $740,845 for the three months ended September 30, 2012. The improvement in operating income is as a result of revenue growth of 97.4% exceeding the 89.4% increase in total operating expenses.
Interest Expense
Interest expense was $1,149,978 for the three months ended September 30, 2013 compared to $490,407 for the three months ended September 30, 2012, an increase of $659,571. 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 September 30, 2013, cash interest expense amounted to $782,030. The remaining non-cash interest expense of $367,948 consisted primarily of deferred financing fees of $314,462 and debt discount amortization of $53,486.
Oil and gas derivatives
Oil and gas derivatives reflected an unrealized loss of $470,433 for the three months ended September 30, 2013 as a result of marking open financial derivative instruments to market as of September 30, 2013 and losses realized on financial derivative instruments settled of $129,399 during the three months then ended. There were no open financial derivative instruments as of September 30, 2012.
Provision for Income Taxes
Provision for income taxes was zero for the three months ended September 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 loss was $198,812 for the three months ended September 30, 2013 compared to net income of $250,976 for the three months ended September 30, 2012. The $809,913 increase in operating income was more than offset by the $659,571 increase in interest expense and the $599,832 expense for oil and gas derivatives in the three months ended September 30, 2013 compared to the three months ended September 30, 2012.
Foreign Currency Translation Loss
Foreign currency translation gain was $1,439 for the three months ended September 30, 2013 compared to a loss of $2,515 for the three months ended September 30, 2012. The Colombian Peso to Dollar Exchange Rate averaged 1,907 and 1,796 for the three month periods ended September 30, 2013 and 2012, respectively and was 1,905 and 1,765 at September 30, 2013 and December 31, 2012.
Comprehensive Income / (Loss)
Comprehensive loss was $197,373 for the three months ended September 30, 2013 compared to a comprehensive income of $248,461 for the three months ended September 30, 2012. The $445,834 decrease was as a result of the $449,788 decrease to a net loss from net income in the current period compared to the prior year period, partially offset by the foreign currency translation gain in the three months ended September 30, 2013 compared to the foreign currency loss in the prior year period.
Nine Months ended September 30, 2013 compared to Nine Months ended September 30, 2012
Our total revenues for the nine months ended September 30, 2013 and 2012 comprised the following:
2013 2012 Change
Amount Percentage Amount Percentage Amount Percentage
Revenues
Oil sales $ 6,301,428 74.3 % $ 3 ,036,599 66.4 % $ 3 ,264,829 107.5 %
Pipeline sales 1,828,256 21.6 % 1 ,396,165 30.5 % 4 32,091 30.9 %
Natural gas sales 348,948 4.1 % 1 37,698 3.0 % 2 11,250 153.4 %
Total revenues $ 8,478,632 100.0 % $ 4 ,570,462 100.0 % $ 3 ,908,170 85.5 %
Oil Sales
Oil Sales were $6,301,428, an increase of $3,264,829, or 107.5%, for the nine months ended September 30, 2013 compared to $3,036,599 for the nine months ended September 30, 2012. Oil sales increased due to an increase in the number of barrels sold and in the average price per barrel. In the United States ("US"), we sold 49,471 barrels ("BBLs") at an average price of $97.87 in the 2013 period, compared to 16,632 BBLs at an average price of $96.64 in the 2012 period. In Colombia, we sold 15,000 BBLs at an average price of $101.49 in the 2013 period compared to 4,000 BBLs at an average price of $107.50 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 $1,828,256, an increase of $432,091, or 30.9% for the nine months ended September 30, 2013 compared to $1,396,165 for the nine months ended September 30, 2012, primarily due to an increase in the number of barrels transported. The number of barrels transported was 9.68 million BBLS (our share was approximately 910,000) and 7.39 million BBLs (our share was approximately 695,000) in the nine months ended September 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 $348,948 for the nine months ended September 30, 2013 compared to $137,698 for the nine months ended September 30, 2012, an increase of $211,250, or 153.4%. All of our natural gas sales are from the well production in Logan County, Oklahoma.
Total revenues were $8,478,632, an increase of $3,908,170, or 85.5% for the nine months ended September 30, 2013 compared to $4,570,462 for the nine months ended September 30, 2012. Oil sales accounted for 74.3% and 66.4% of total revenues in the 2013 and 2012 periods, respectively.
Production
For the nine months ended September 30, 2013 and 2012, our production was as
follows:
