Item 1. Business
Overview
Oasis Petroleum Inc. (together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources in the Montana and North Dakota regions of the Williston Basin. As of December 31, 2012, we have accumulated 335,383 net leasehold acres in the Williston Basin. We are currently exploiting significant resource potential from the Bakken and Three Forks formations, which are present across a substantial portion of our acreage. We believe the location, size and concentration of our acreage in our core project areas create an opportunity for us to achieve cost, recovery and production efficiencies through the large-scale development of our project inventory. Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs, which we refer to as “resource conversion” opportunities, and has substantial Williston Basin experience. In 2012, we completed and placed on production 117 gross operated wells in the Williston Basin. We have built our Williston Basin leasehold acreage position primarily through acquisitions and development in our three primary project areas: West Williston, East Nesson and Sanish.
DeGolyer and MacNaughton, our independent reserve engineers, estimated our net proved reserves to be 143.3 MMBoe as of December 31, 2012, of which 49% were classified as proved developed and of which 89% were oil. The following table presents summary data for each of our primary project areas as of December 31, 2012:
Our history
Oasis Petroleum Inc. was incorporated in February 2010 pursuant to the laws of the State of Delaware to become a holding company for Oasis Petroleum LLC (“OP LLC”), our predecessor, which was formed as a Delaware limited liability company in February 2007 by certain members of our senior management team and certain private equity funds. We completed our initial public offering (“IPO”) in June 2010. In connection with our IPO and related corporate reorganization, we acquired all of the outstanding membership interests in OP LLC in exchange for shares of our common stock. Oasis Petroleum North America LLC (“OPNA”) conducts our exploration and production activities and owns our proved and unproved oil and natural gas properties. In 2011, we formed Oasis Well Services LLC (“OWS”), which provides well services to OPNA, and Oasis Petroleum Marketing LLC (“OPM”), which provides marketing services to OPNA.
Our business strategy
Our goal is to enhance value by investing capital to build reserves, production and cash flows at attractive rates of return through the following strategies:
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Develop our Williston Basin leasehold position. We intend to continue to drill and develop our acreage position to maximize the value of our resource potential. During 2012, we completed and brought on production 117 gross (95.8 net) operated Bakken and Three Forks wells in the Williston Basin. As of December 31, 2012, we had 21 gross operated wells waiting on completion and 11 gross operated wells drilling in the Bakken and Three Forks formations. Our 2013 drilling plan contemplates completing approximately 128 gross (92.5 net) operated wells in our project areas. We believe we have the ability to increase or decrease the number of wells drilled during 2013 based on market conditions and program results.
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Focus on operational and cost efficiencies. Our management team is focused on continuous improvement of our operations and has significant experience in successfully converting early-stage resource conversion opportunities into cost-efficient development projects. We believe the magnitude and concentration of our acreage within our project areas provide us with the opportunity to capture economies of scale, including the ability to drill multiple wells from a single drilling pad, utilizing centralized production and oil, gas and water fluid handling facilities and infrastructure and reducing the time and cost of rig mobilization. In addition, OWS is expected to continue to provide capital savings and decrease our operated well capital costs going forward.
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Adopt and employ leading drilling and completion techniques. Our team is focused on enhancing our drilling and completion techniques to maximize overall well economics. We believe these techniques have significantly evolved over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the implementation of techniques such as drilling longer laterals and more tightly spacing fracturing stimulation stages. We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our operating practices. This continued evolution may enhance our initial production rates, ultimate recovery factors and rate of return on invested capital.
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Pursue strategic acquisitions with significant resource potential. As opportunities arise, we intend to identify and acquire additional acreage and producing assets in the Williston Basin to supplement our existing operations. Going forward, we may selectively target additional basins that would allow us to employ our resource conversion strategy on large undeveloped acreage positions similar to what we have accumulated in the Williston Basin.
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Maintain financial flexibility and conservative financial position. We are committed to maintaining a conservative financial strategy by managing our liquidity position and leverage levels. As of December 31, 2012, we had no borrowings and $2.2 million of outstanding letters of credit under our revolving credit facility and $737.1 million of liquidity available, including $239.3 million in cash and short-term investments and $497.8 million available under our revolving credit facility. This liquidity position, along with internally generated cash flows, will provide additional financial flexibility as we continue to develop our acreage position in the Williston Basin. We also have access to the public equity and debt markets, and we intend to maintain a conservative, balanced capital structure by prudently raising proceeds from future offerings as additional capital needs arise.
Our competitive strengths
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:
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Substantial leasehold position in one of North America’s leading unconventional oil-resource plays. As of December 31, 2012, our 335,383 net leasehold acres in the Williston Basin were highly prospective in the Bakken and Three Forks formations and 89% of our 143.3 MMBoe estimated net proved reserves in this area were comprised of oil. We increased our operated drill blocks by 37 through acreage additions and trades during 2012. In addition, we have 264,595 net acres held-by-production as of December 31, 2012. We believe our acreage is one of the largest concentrated leasehold positions that is prospective in the Bakken and Three Forks formations, and much of our acreage is in areas of significant drilling activity by other exploration and production companies. We expect that the scale and concentration of our acreage will enable us to reduce our drilling and completion costs and improve operational efficiency as we transition to full development mode throughout 2013.
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Large, multi-year project inventory. We believe we have a large inventory of potential drilling locations that we have not yet drilled, a majority of which is operated by us. We plan to complete 128 gross (92.5 net) operated wells in the Williston Basin in 2013.
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Management team with proven operating and acquisition skills. Our senior management team has extensive expertise in the oil and gas industry. Our senior technical team has an average of more than 25 years of industry experience, including experience in multiple North American resource plays as well as experience in international basins. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of resource conversion opportunities. In addition, our technical team possesses substantial expertise in horizontal drilling techniques and managing and acquiring large development programs and also has prior experience in the Williston Basin.
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Incentivized management team. As of December 31, 2012, our executive officers owned approximately 5% of our outstanding common stock. We believe our executive officers’ ownership interest in us provides them with significant incentives to grow the value of our business for the benefit of all stakeholders.
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Operating control over the majority of our portfolio. In order to maintain better control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate. We expect to operate approximately 64% of our gross drilling locations, or 91% of our net drilling locations. As of December 31, 2012, 93% of our estimated net proved reserves were attributable to properties that we expect to operate. Approximately 89% of our 2013 drilling and completion capital expenditure budget is related to operated wells. As of December 31, 2012, our average working interest in our operated and non-operated identified drilling locations was 69% and 12%, respectively. Controlling operations will allow us to dictate the pace of development as well as the costs, type and timing of exploration and development activities. We believe that maintaining operational control over the majority of our acreage will allow us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing hydrocarbon recovery through continuous improvement of drilling and completion techniques. We are also better able to control infrastructure investment to drive down operating costs and increase gas production and oil price realizations.
Our operations
Estimated net proved reserves
The table below summarizes our estimated net proved reserves and related PV-10 at December 31, 2012, 2011 and 2010 for each of our project areas based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers. In preparing its reports, DeGolyer and MacNaughton evaluated properties representing all of our PV-10 at December 31, 2012, 2011 and 2010 in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in oil and natural gas producing activities. Our estimated net proved reserves were determined using the preceding twelve months’ unweighted arithmetic average of the first-day-of-the-month prices and do not include probable or possible reserves. The information in the following table does not give any effect to or reflect our commodity derivatives. For a definition of proved reserves under the SEC rules, please see the “Glossary of oil and natural gas terms” included at the end of this report. For more information regarding our independent reserve engineers, please see “Independent petroleum engineers” below.
(1) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable financial measure under accounting principles generally accepted in the United States of America (“GAAP”), because it does not include the effect of income taxes on discounted future net cash flows. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. The oil and gas industry uses PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. See “Reconciliation of PV-10 to Standardized Measure” below.
(2) Represents data relating to our properties in the Barnett shale, which we sold in November 2011.
Estimated net proved reserves at December 31, 2012 were 143.3 MMBoe, an 82% increase from estimated net proved reserves of 78.7 MMBoe at December 31, 2011 primarily as a result of our 2012 drilling program and well completions. Our proved developed reserves increased 34.2 MMBoe, or 95%, to 70.0 MMBoe for the year ended December 31, 2012 from 35.8 MMBoe for the year ended December 31, 2011, primarily due to our 2012 drilling program, including the completion of 117 gross (95.8 net) operated wells. Our proved undeveloped reserves increased to 73.3 MMBoe for the year ended December 31, 2012 from 42.9 MMBoe for the year ended December 31, 2011 primarily due to our 2012 drilling program.
Estimated net proved reserves at December 31, 2011 were 78.7 MMBoe, a 98% increase from estimated net proved reserves of 39.8 MMBoe at December 31, 2010. Our 2011 estimated net proved reserves increased 38.9 MMBoe over our 2010 estimated net proved reserves due to acquisitions, our drilling program and higher oil price assumptions at December 31, 2011. Our commodity price assumption for oil increased $16.83/Bbl to $96.23/Bbl for the year ended December 31, 2011 from $79.40/Bbl for the year ended December 31, 2010. Our proved developed producing reserves increased 18.8 MMBoe, or 111%, to 35.8 MMBoe for the year ended December 31, 2011 from 17.0 MMBoe for the year ended December 31, 2010, primarily due to our drilling program completing 63 gross (49.2 net) operated wells. Our proved undeveloped reserves increased to 42.9 MMBoe for the year ended December 31, 2011 from 22.8 MMBoe for the year ended December 31, 2010 due to our drilling program, significant regional drilling activity, higher commodity price assumptions and higher overall estimated ultimate recoveries using recent drilling and completion techniques.
The following table sets forth more information regarding our estimated net proved reserves at December 31, 2012, 2011 and 2010:
(1) Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $94.68/Bbl for oil and $2.75/MMBtu for natural gas, $96.23/Bbl for oil and $4.12/MMBtu for natural gas, and $79.40/Bbl for oil and $4.38/MMBtu for natural gas for the years ended December 31, 2012, 2011 and 2010, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
(2) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. The oil and gas industry uses PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. See “Reconciliation of PV-10 to Standardized Measure” below.
(3) Standardized Measure represents the present value of estimated future net cash flows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses (if applicable), discounted at 10% per annum to reflect timing of future cash flows.
Reconciliation of PV-10 to Standardized Measure
PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.
The following table provides a reconciliation of PV-10 to the Standardized Measure of discounted future net cash flows at December 31, 2012, 2011 and 2010:
The PV-10 of our estimated net proved reserves at December 31, 2012 was $3,244.3 million, a 70% increase from PV-10 of $1,903.7 million at December 31, 2011. This increase was mainly due to an increase in reserves and a reduction in costs, partially offset by lower commodity price assumptions year over year.
Estimated future net revenues
The following table sets forth the estimated future net revenues, excluding derivative contracts, from proved reserves, the present value of those net revenues (PV-10) and the expected benchmark prices used in projecting net revenues at December 31, 2012, 2011 and 2010:
(1) Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $94.68/Bbl for oil and $2.75/MMBtu for natural gas, $96.23/Bbl for oil and $4.12/MMBtu for natural gas, and $79.40/Bbl for oil and $4.38/MMBtu for natural gas for the years ended December 31, 2012, 2011 and 2010, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations at December 31, 2012, 2011 and 2010 are based on costs in effect at December 31 of each year and the twelve-month unweighted arithmetic average of the first-day-of-the-month price for January through December of such year, without giving effect to derivative transactions, and are held constant throughout the life of the properties. There can be no assurance that the proved reserves will be produced within the periods indicated or that prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.
Proved undeveloped reserves
At December 31, 2012, we had approximately 73.3 MMBoe of proved undeveloped reserves as compared to 42.9 MMBoe at December 31, 2011.
The following table summarizes the changes in our proved undeveloped reserves during 2012 (in MBoe):
During 2012, we spent a total of $642.7 million related to the development of proved undeveloped reserves, $90.0 million of which was spent on proved undeveloped reserves that still remain proved undeveloped at year-end. The remaining $552.7 million resulted in the conversion of 26,493MBoe of proved undeveloped reserves, or 62% of our proved undeveloped reserves balance at the beginning of 2012, to proved developed reserves. We added 57,322 MBoe of proved undeveloped reserves across all three of our project areas as a result of our 2012 operated and non-operated drilling program.
In 2012, we also had a net negative revision of 1,223 MBoe, or 2.9 % of our December 31, 2011 proved undeveloped reserves balance. The primary causes for these revisions were negative well performances partially offset by working interest increases in the proved undeveloped locations. Within portions of the West Williston and East Nesson project areas, actual well results underperformed relative to the proved undeveloped forecasts prepared in 2011. The proved undeveloped forecasts in these areas have been adjusted to reflect these well performances in the 2012 reserve report. The working interest increases arose from acreage trades, non-participation by other interest owners and additional mineral leasing in the reserve locations. Operating costs and realized prices had an immaterial impact on the proved undeveloped reserves balance.
All of our proved undeveloped reserves as of December 31, 2012 are expected to be developed within five years of their initial booking.
Independent petroleum engineers
Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure at December 31, 2012, 2011 and 2010 are based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007) and definitions and current guidelines established by the SEC. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Calgary and Moscow. The firm’s more than 100 professionals include engineers, geologists, geophysicists, petrophysicists and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton has provided such services for over 70 years. The Senior Vice President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve estimates is a Registered Petroleum Engineer in the State of Texas with more than 35 years of experience in oil and gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1974 and he is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any oil, gas or mineral properties, or securities or notes of clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.
Technology used to establish proved reserves
In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated net proved reserves, DeGolyer and MacNaughton employed technologies including, but not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available down hole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. In addition to assessing reservoir continuity, geologic data from well logs, core analyses and seismic data related to the Bakken formation were used to estimate original oil in place. In areas where estimated proved reserves were attributed to more than one well per spacing unit, the estimated original oil in place was used to calculate reasonable estimated recovery factors based on experience with similar reservoirs where similar drilling and completion techniques have been employed.
Internal controls over reserves estimation process
We employ DeGolyer and MacNaughton as the independent reserves evaluator for 100% of our reserves base. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with the independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished for the reserves estimation process. Brett Newton, Senior Vice President of Asset Management, is the technical person primarily responsible for overseeing our reserves evaluation process. He has over 20 years of industry experience with positions of increasing responsibility in engineering and management. He holds both a Bachelor of Science degree and Master of Science degree in petroleum engineering. Mr. Newton reports directly to our Chief Operating Officer.
Throughout each fiscal year, our technical team meets with the independent reserve engineers to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following:
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Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database;
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Review of working interest and net revenue interest in our reserves database against our well system;
• Review of realized prices and differentials from index prices from the well profitability report as compared to the differentials used in our reserves database;
• Review of updated capital costs prepared by our operations team;
• Review of internal reserve estimates by well and by area by our internal reservoir engineers;
• Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President of Asset Management;
• Review of a preliminary copy of the reserve report by our Chief Operating Officer with representatives from our independent reserve engineers and internal technical staff; and
• Review of our reserves estimation process by our Audit Committee on an annual basis.
Production, revenues and price history
Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically over the last ten years. However, the economic slowdown during the second half of 2008 and through 2009 reduced this demand. In 2010, 2011 and 2012, demand for oil and natural gas increased as the economy recovered. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.
The following table sets forth information regarding our oil and natural gas production, realized prices and production costs for the periods indicated. For additional information on price calculations, please see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
(1) Realized prices include realized gains or losses on cash settlements for our commodity derivatives, which do not qualify for and were not designated as hedging instruments for accounting purposes.
(2) Natural gas prices include the value for natural gas and natural gas liquids.
(3) For the years ended December 31, 2011 and 2010, lease operating expenses exclude marketing, transportation and gathering expenses to conform such amounts to current year classifications.
(4) During 2010, we recorded $8.7 million in stock-based compensation expense associated with Class C common unit interests (“C Units”) and discretionary stock awards granted. Stock-based compensation expense related to the amortization of restricted stock and performance share units is included in general and administrative expenses on the Consolidated Statement of Operations. See Note 9 to our audited consolidated financial statements.
Net production volumes for the year ended December 31, 2012 were 8,224 MBoe, a 110% increase from net production of 3,914 MBoe for the year ended December 31, 2011. Our net production volumes increased 4,310 MBoe over 2011 due to a successful operated and non-operated drilling and completion program. Average oil sales prices, without realized derivatives, decreased by $0.96/Bbl, or 1%, to an average of $85.22/Bbl for the year ended December 31, 2012 as compared to the year ended December 31, 2011. Giving effect to our derivative transactions in both periods, our oil sales prices increased $0.94/Bbl to $86.09/Bbl for the year ended December 31, 2012 from $85.15/Bbl for the year ended December 31, 2011.
Net production volumes for the year ended December 31, 2011 were 3,914 MBoe, a 106% increase from net production of 1,900 MBoe for the year ended December 31, 2010. Our net production volumes increased 2,014 MBoe over 2010 due to a successful operated and non-operated drilling and completion program. Average oil sales prices, without realized derivatives, increased by $16.58/Bbl, or 24%, to an average of $86.18/Bbl for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Giving effect to our derivative transactions in both periods, our oil sales prices increased $15.62/Bbl to $85.15/Bbl for the year ended December 31, 2011 from $69.53/Bbl for the year ended December 31, 2010.
The following table sets forth information regarding our average daily production for the years ended December 31, 2012 and 2011:
(1) Represents data relating to our properties in the Barnett shale, which we sold in November 2011.
Productive wells
The following table presents the total gross and net productive wells by project area as of December 31, 2012:
All of our productive wells are oil wells. Gross wells are the number of wells, operated and non-operated, in which we own a working interest and net wells are the total of our working interests owned in gross wells.
Acreage
The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2012 for each of our project areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.
We have increased our acreage that is held-by-production to approximately 265 thousand net acres at December 31, 2012 from 184 thousand net acres at December 31, 2011.
Undeveloped acreage
The following table sets forth the number of gross and net undeveloped acres as of December 31, 2012 that will expire over the next three years by project area unless production is established within the spacing units covering the acreage prior to the expiration dates:
Drilling activity
The following table summarizes our drilling activity for the years ended December 31, 2012, 2011 and 2010. Gross wells reflect the sum of all productive and dry wells, operated and non-operated, in which we own an interest. Net wells reflect the sum of our working interests in gross wells. The gross and net wells represent wells completed during the periods presented, regardless of when drilling was initiated.
(1) In 2012, we had two gross development dry hole wells as a result of mechanical failures. Replacement wells were drilled in the same drilling spacing units, which were successful in finding and producing hydrocarbons.
Our drilling activity has increased each year since our inception. Exploration wells in 2011 and 2010 primarily focused on delineation and appraisal of the Bakken formation in our West Williston and East Nesson areas. In 2012, we continued this focus on delineation, resulting in substantially all of our acreage being delineated in the Bakken formation and continued delineation in the Three Forks formation as of December 31, 2012. We also continued to participate in a number of wells on a non-operated basis.
In 2012, we had two gross development dry hole wells as a result of mechanical failures. Replacement wells were drilled in the same drilling spacing units, which were successful in finding and producing hydrocarbons. In 2012 and 2011, we allocated a portion of the costs for a well that was unsuccessful due to mechanical complications in the Three Forks formation to exploratory dry hole expense. The well was successfully plugged back and completed in the Bakken formation. We did not drill any dry hole wells in 2010. Consistent with our 2013 capital plan, we expect to continue to focus on drilling in the Bakken and Three Forks formations.
Capital expenditure budget
In 2012, we spent $1,148.6 million on capital expenditures, which represented a 72% increase over the $666.0 million spent during 2011. This increase was a result of continued improvement of industry conditions and drilling and completion technology in the Bakken and Three Forks formations as well as increased economics in the area and an increase in total net wells drilled in 2012. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and capital resources-Cash flows used in investing activities.”
Our total 2013 capital expenditure budget is $1,020 million, which includes $996 million for exploration and production (“E&P”) capital expenditures and $24 million for non-E&P capital expenditures. Our planned capital expenditures primarily consist of:
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$897 million of drilling and completion capital expenditures for operated and non-operated wells (including expected savings from services provided by OWS);
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$43 million for constructing infrastructure to support production in our core project areas, primarily related to salt water disposal systems;
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$25 million for maintaining and expanding our leasehold position;
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$10 million for micro-seismic work, purchasing seismic data and other test work;
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$21 million for facilities and other miscellaneous E&P capital expenditures;
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$14 million for OWS; and
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$10 million for other non-E&P capital, including items such as administrative capital and capitalized interest.
While we have budgeted $1,020 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and capital resources.”
Our core project areas
Williston Basin
Our operations are focused in the North Dakota and Montana areas of the Williston Basin. While we have interests in a substantial number of wells in the Williston Basin that target several different zones, our exploration and development activities are currently concentrated in the Bakken and Three Forks formations. Our management team originally targeted the Williston Basin because of its oil prone nature, multiple, stacked producing horizons, substantial resource potential and management’s previous professional history in the basin. The Williston Basin also has established infrastructure and access to materials and services. Regulatory delays are minimal in the Williston Basin due to fee ownership of properties, efficient state and local regulatory bodies and reasonable permitting requirements.
The entire Williston Basin is spread across North Dakota, South Dakota, Montana and parts of southern Canada. The basin produces oil and natural gas from numerous producing horizons including, but not limited to, the Bakken, Three Forks, Madison and Red River formations. The Williston Basin is now one of the most actively drilled unconventional oil resource plays in the United States, with approximately 195 rigs drilling in the basin, including 184 in North Dakota and 11 in Montana, based on Anderson Reports’ weekly rig count dated January 3, 2013. A report issued by the United States Geological Survey in April 2008 classified these formations as the largest continuous oil accumulation ever assessed by it in the contiguous United States.
The Devonian-age Bakken formation is found within the Williston Basin underlying portions of North Dakota and Montana and is comprised of three lithologic members including the upper shale, middle Bakken and lower shale. The formation ranges up to 150 feet thick. The upper and lower shales are highly organic, thermally mature and over pressured and can act as both a source and reservoir for the oil. The middle Bakken, which varies in composition from a silty dolomite to shaley limestone or sand, also serves as a reservoir and is a critical component for commercial production. Generally, the Bakken formation is found at vertical depths of 8,500 to 11,500 feet. Based on our geologic interpretation of the Bakken formation, the evolution of completion techniques, our own drilling results and publicly available drilling results for other operators in the basin, we believe that a substantial portion of our Williston Basin acreage is prospective in the Bakken formation.
The Three Forks formation, generally found immediately under the Bakken formation, has also proven to contain productive reservoir rock that may add incremental reserves to our existing leasehold positions. The Three Forks formation typically consists of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as Sanish sand. The Three Forks formation is an unconventional carbonate play. Based on our geologic interpretation of the Three Forks formation, the evolution of completion techniques, our own drilling results and publicly available drilling results for other operators in the basin, we believe that much of our Williston Basin acreage is prospective in the Three Forks formation.
Our total leasehold position in the Williston Basin as of December 31, 2012 consisted of 335,383 net acres. Our estimated net proved reserves in the Williston Basin were 143.3 MMBoe at December 31, 2012. Of our estimated net proved reserves in the Williston Basin, approximately 70.0 MMBoe were proved developed reserves, which are comprised of a combination of wells drilled to conventional reservoirs, Bakken wells drilled with older completion techniques and Bakken and Three Forks wells drilled with completion techniques similar to those we currently employ. Based on our results to date, we estimate that the Bakken and Three Forks wells drilled with more recent completion techniques will achieve estimated ultimate recovery rates that will in many cases more than double the ultimate recovery rates we expect from the Bakken wells with older completion techniques. Based on publicly available information for other operators in the basin, we believe this trend towards higher recovery rates is generally consistent across the basin. Of our estimated net proved reserves, 73.3 MMBoe were proved undeveloped reserves, all of which consisted of Bakken and Three Forks wells to be drilled with more recent completion techniques. We expect that all of our identified drilling locations in each of our project areas will be drilled and completed using completion techniques similar to those we currently employ.
As of December 31, 2012, we had a total of 263.6 net operated and non-operated producing wells and 227.8 net operated producing wells in the Williston Basin. We had average daily production of 22,469 net Boe/d for the year ended December 31, 2012 in the Williston Basin. During 2012, our Bakken and Three Forks wells produced a daily average of 21,766 net Boe/d with 216.2 net producing wells on December 31, 2012. Accordingly, our 216.2 net Bakken and Three Forks wells were responsible for 97% of our average daily production during 2012. As of December 31, 2012, our working interest for all producing wells averaged 37% and in the wells we operate was approximately 82%. As of December 31, 2012, we were drilling or completing 69 gross (25.6 net) wells in the Williston Basin. We participated in 231 gross (105.6 net) wells that were completed and brought on production during 2012.
Currently, we estimate our capital expenditures for 2013 will be $1,020 million, which includes completing 128 gross (92.5 net) horizontal operated wells, participating in 10.9 net non-operated wells that are expected to be completed and brought on production, construction of infrastructure to support production and leasehold acquisitions. Since most of this capital is expected to be spent on horizontal drilling in the Bakken and Three Forks formations, we expect that the proportion of our production from these formations will grow in the future.
Our Williston Basin activities are evaluated in three primary areas of operations: West Williston, East Nesson and Sanish.
West Williston
We control 208,062 net acres in the West Williston project area, primarily in Williams and McKenzie counties in North Dakota and Roosevelt and Richland counties in Montana. We had average daily production of 15,263 net Boe/d for the year ended December 31, 2012, 95% of which was produced from the Bakken and Three Forks formations and the remainder from other conventional formations. As of December 31, 2012, we had an average working interest of 57% and operated 94% of our 176.2 net producing wells in the West Williston project area. As of December 31, 2012, we operated 97% of our 128.8 net producing Bakken and Three Forks wells in the West Williston project area.
During the year ended December 31, 2012, our total completions were 94 gross (67.4 net) horizontal Bakken and Three Forks wells in the West Williston project area. As of December 31, 2012, we were participating in drilling or completion of 29 gross (16.3 net) wells in this project area. We have budgeted $520 million in capital expenditures in the West Williston project area in 2013 for the completion of 75 gross (55.3 net) operated wells and 2.9 net non-operated wells.
East Nesson
We control 118,943 net acres in the East Nesson project area, primarily in Mountrail and Burke counties in North Dakota. We had average daily production of 4,936 net Boe/d for the year ended December 31, 2012, all of which was produced from the Bakken and Three Forks formations. As of December 31, 2012, we had an average working interest of 47% and operated 91% of our 67.5 net producing wells in the East Nesson project area, all of which are producing out of the Bakken and Three Forks formations.
During the year ended December 31, 2012, our total completions were 54 gross (31.4 net) horizontal Bakken and Three Forks wells in the East Nesson project area. As of December 31, 2012, we were participating in the drilling or completion of 24 gross (8.4 net) wells in this project area. We have budgeted $329 million in capital expenditures in the East Nesson project area in 2013 for the completion of 53 gross (37.2 net) operated wells and 2.3 net non-operated wells.
Sanish
We have 8,378 net acres in the Sanish project area, all of which are located in Mountrail County in North Dakota. We had average daily production of 2,270 net Boe/d for the year ended December 31, 2012, all of which was produced from the Bakken and Three Forks formations. As of December 31, 2012, we had an average working interest of 8% in our 19.9 net wells in the Sanish project area. Our properties in this project area are entirely operated by other operators, the largest of which are Whiting Petroleum Corporation and Fidelity Exploration.
During the year ended December 31, 2012, our total completions were 83 gross (6.8 net) horizontal Bakken and Three Forks wells in the Sanish project area. As of December 31, 2012, we were participating in the drilling or completion of 16 gross (0.9 net) wells in this project area. We have budgeted $48 million in capital expenditures in the Sanish project area in 2013 for the completion of 5.8 net non-operated wells.
Marketing, transportation and major customers
The Williston Basin crude oil transportation and refining infrastructure has grown substantially in recent years, largely in response to drilling activity in the Bakken formation. In December 2012, oil production in North Dakota was approximately 769,000 barrels per day compared to approximately 535,000 barrels per day in December 2011. According to a presentation from the North Dakota Pipeline Authority dated January 11, 2013, there were approximately 463,000 barrels per day of crude oil pipeline transportation capacity in the Williston Basin as of December 31, 2012. In addition, approximately 670,000 barrels per day of specifically dedicated railcar transportation capacity has been placed into service as of December 31, 2012. In 2012, we began selling a significant amount of our crude oil production from our West Williston project area through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. As of December 31, 2012, we flowed approximately 60% of our gross operated oil production through these gathering systems. We will continue to implement wellhead gathering of crude oil in 2013 with the implementation of gathering connections in our East Nesson project area, which we expect will increase the gross operated oil production that will flow on these systems to over 80% by mid-year 2013.
Recent expansion of both rail and pipeline facilities has reduced the previous constraint on oil transportation out of the Williston Basin and improved netback pricing received at the lease. However, oil from Canada has put pressure on the existing pipeline infrastructure from the Williston Basin that terminates at Midwest refineries. In addition, although there were 670,000 barrels per day of railcar transportation capacity in place as of December 31, 2012, these railcar facilities are not yet running at nameplate capacity due to initial commissioning, limited crude oil supply and limited availability of railcars. We believe the operators of these railcar facilities have railcars on order and expect utilization on these facilities to continue to increase substantially during 2013. For a discussion of the potential risks to our business that could result from transportation and refining infrastructure constraints in the Williston Basin, please see “Item 1A.
Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.
Risks related to the oil and natural gas industry and our business
A substantial or extended decline in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The price we receive for our oil and, to a lesser extent, natural gas, heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
• worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
• the actions of OPEC;
• the price and quantity of imports of foreign oil and natural gas;
• political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America, China, India and Russia;
• the level of global oil and natural gas exploration and production;
• the level of global oil and natural gas inventories;
• localized supply and demand fundamentals and regional, domestic and international transportation availability;
• weather conditions and natural disasters;
• domestic and foreign governmental regulations;
• speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
• price and availability of competitors’ supplies of oil and natural gas;
• technological advances affecting energy consumption; and
• the price and availability of alternative fuels.
Substantially all of our production is sold to purchasers under short-term (less than twelve-month) contracts at market-based prices. Lower oil and natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. See “Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves.” Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our proved reserves. See also “The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves” below.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” below. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
• shortages of or delays in obtaining equipment and qualified personnel;
• facility or equipment malfunctions and/or failure;
• unexpected operational events, including accidents;
• pressure or irregularities in geological formations;
• adverse weather conditions, such as blizzards, ice storms and floods;
• reductions in oil and natural gas prices;
• delays imposed by or resulting from compliance with regulatory requirements;
• proximity to and capacity of transportation facilities;
• title problems; and
• limitations in the market for oil and natural gas.
Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See “Item 1. Business-Our operations” for information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net revenues as of December 31, 2012, 2011 and 2010.
In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by our independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. In addition, we may adjust estimates of net proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.
The present value of future net revenues from our estimated net proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the present value of future net revenues from our estimated net proved reserves is the current market value of our estimated net oil and natural gas reserves. In accordance with SEC requirements for the years ended December 31, 2012, 2011 and 2010, we based the estimated discounted future net revenues from our estimated net proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:
•
actual prices we receive for oil and natural gas;
•
actual cost of development and production expenditures;
•
the amount and timing of actual production; and
•
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from estimated net proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report on Form 10-K. Any significant future price changes will have a material effect on the quantity and present value of our estimated net proved reserves.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.
Operations in the Bakken and the Three Forks formations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage.
Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Bakken and Three Forks formations is limited. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate. We could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future.
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net oil and natural gas reserves.
Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. We spent $1,148.6 million and $666.0 million related to capital expenditures for the years ended December 31, 2012 and 2011, respectively. Our capital expenditure budget for 2013 is approximately $1,020 million, with approximately $897 million allocated for drilling and completion operations. Since our IPO, our capital expenditures have been financed with proceeds from our IPO, net cash provided by operating activities and proceeds from our $1.2 billion of senior unsecured notes. DeGolyer and MacNaughton projects that we will incur capital costs (including abandonment obligations) in excess of $1,324 million over the next four years to develop the proved undeveloped reserves in the Williston Basin covered by its December 31, 2012 reserve report. Because these costs cover less than 25% of our net primary drilling locations, we will be required to generate or raise multiples of this amount of capital to develop all of our potential drilling locations should we elect to do so. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
A significant improvement in product prices could result in an increase in our capital expenditures. We intend to finance our future capital expenditures primarily through net proceeds from our previous issuances of senior unsecured notes, cash flows provided by operating activities, and borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of additional debt or equity securities or the sale of non-strategic assets. The issuance of additional debt or equity may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under our revolving credit facility will be automatically reduced by an amount equal to 25% of the aggregate principal amount of such debt securities.
Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:
• our estimated net proved reserves;
• the level of oil and natural gas we are able to produce from existing wells and new projected wells;
• the prices at which our oil and natural gas are sold;
• the costs of developing and producing our oil and natural gas production;
• our ability to acquire, locate and produce new reserves;
• the ability and willingness of our banks to lend; and
• our ability to access the equity and debt capital markets.
If the borrowing base under our revolving credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.
If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount available under our revolving credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our revolving credit facility and our results of operations for the periods in which such charges are taken. No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2012, 2011 and 2010.
We will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.
We expect that we will not be the operator on approximately 38% of our identified gross drilling locations (approximately 9% of our identified net drilling locations). As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:
• the timing and amount of capital expenditures;
• the operator’s expertise and financial resources;
• approval of other participants in drilling wells;
• selection of technology; and
• the rate of production of reserves, if any.
This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.
All of our producing properties and operations are located in the Williston Basin region, making us vulnerable to risks associated with operating in one major geographic area.
As of December 31, 2012, 100% of our proved reserves and production were located in the Williston Basin in northeastern Montana and northwestern North Dakota. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
Our business depends on oil and natural gas gathering and transportation facilities, most of which are owned by third parties.
The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. See also “Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production” and “Insufficient transportation or refining capacity in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.” We generally do not purchase firm transportation on third party pipeline facilities, and therefore, the transportation of our production can be interrupted by other customers that have firm arrangements.
The disruption of third-party facilities due to maintenance, weather or other interruptions of service could also negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored. A total shut-in of our production could materially affect us due to a resulting lack of cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow.
Insufficient transportation or refining capacity in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.
The Williston Basin crude oil business environment has historically been characterized by periods when oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for WTI crude oil. Although additional Williston Basin transportation takeaway capacity was added in 2011 and 2012, production also increased due to the elevated drilling activity in these years. The increased production coupled with delays in rail car arrivals and commissioning of rail loading facilities caused price differentials at times to be at the high-end of the historical average range of approximately 10% to 15% of the WTI crude oil index price in the first half of 2012. During the second half of 2012, differentials improved due to expanding rail infrastructure and pipeline expansions coming online. On barrels that are transported over pipelines to either Clearbrook, Minnesota or Guernsey, Wyoming, our realized price for crude oil is generally the quoted price for Bakken crude oil less transportation costs from the point where the crude oil is sold.
The development of our proved undeveloped reserves in the Williston Basin and other areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
Approximately 51% of our estimated net proved reserves were classified as proved undeveloped as of December 31, 2012. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our estimated net proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
• environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gas or other pollutants into the environment;
• abnormally pressured formations;
• shortages of, or delays in, obtaining water for hydraulic fracturing activities;
• mechanical difficulties, such as stuck oilfield drilling and service tools and casing failure;
• personal injuries and death; and
• natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
• injury or loss of life;
• damage to and destruction of property, natural resources and equipment;
• pollution and other environmental damage;
• regulatory investigations and penalties;
• suspension of our operations; and
• repair and remediation costs.
We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
We have incurred losses in prior years and may do so again in the future.
For the years ended December 31, 2012 and 2011, we had net income of $153.4 million and $79.4 million, respectively. However, for the year ended December 31, 2010, we incurred a net loss of $29.7 million. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures, including planned capital expenditures for 2013 of approximately $1,020 million.
The uncertainty and risks described in this Annual Report on Form 10-K may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.
Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.
We describe some of our drilling locations and our plans to explore those drilling locations in this Annual Report on Form 10-K. Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Williston Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.
Our potential drilling location inventories are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.
Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, 2012, we had leases representing 22,461 net acres expiring in 2013, 9,970 net acres expiring in 2014 and 35,011 net acres expiring in 2015. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business. During each of the years ended December 31, 2012 and 2011, we recorded non-cash impairment charges of $3.6 million, and during the year ended December 31, 2010, we recorded non-cash impairment charges of $12.0 million on our unproved properties due to expiring leases and periodic assessments of our unproved properties.
Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing occupational health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of a permit before conducting drilling or underground injection activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of our operations.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and waste water discharges related to our operations and due to historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our financial condition or results of well drilling, construction, completion on water management activities or operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.
Failure to comply with federal, state and local laws could adversely affect our ability to produce, gather and transport our oil and natural gas and may result in substantial penalties.
Our operations are substantially affected by federal, state and local laws and regulations, particularly as they relate to the regulation of oil and natural gas production and transportation. These laws and regulations include regulation of oil and natural gas exploration and production and related operations, including a variety of activities related to the drilling of wells, the interstate transportation of oil and natural gas by federal agencies such as the FERC, as well as state agencies. In addition, federal laws prohibit market manipulation in connection with the purchase or sale of oil and/or natural gas. Failure to comply with federal, state and local laws could adversely affect our ability to produce, gather and transport our oil and natural gas and may result in substantial penalties. Please see “Other federal laws and regulations affecting our industry.”
Climate change legislation and regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
Based on findings by the EPA in December 2009 that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the Earth’s atmosphere and other climatic changes, the EPA adopted regulations under existing provisions of the CAA that establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas production facilities on an annual basis, which includes certain of our operations. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. The adoption and implementation of any legislation or regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.
Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
The loss of senior management or technical personnel could adversely affect our operations.
To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Thomas B. Nusz, our Chairman, President and Chief Executive Officer, and Taylor L. Reid, our Executive Vice President and Chief Operating Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in the Williston Basin are adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Severe winter weather conditions limit and may temporarily halt our ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs.
Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.
Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:
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production is less than the volume covered by the derivative instruments;
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the counterparty to the derivative instrument defaults on its contract obligations; or
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there is an increase in the differential between the underlying price in the derivative instrument and actual price received.
In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.
The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate and other risks associated with our business.
On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012, although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” The Dodd-Frank Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows.
Increased costs of capital could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
We may not be able to generate enough cash flow to meet our debt obligations.
We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:
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selling assets;
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reducing or delaying capital investments;
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seeking to raise additional capital; or
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refinancing or restructuring our debt.
If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on our senior unsecured notes. If amounts outstanding under our revolving credit facility or our senior unsecured notes were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and capital resources.”
Our revolving credit facility and the indentures governing our senior unsecured notes all contain operating and financial restrictions that may restrict our business and financing activities.
Our revolving credit facility and the indentures governing our senior unsecured notes contain a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:
• sell assets, including equity interests in our subsidiaries;
• pay distributions on, redeem or repurchase our common stock or redeem or repurchase our subordinated debt;
• make investments;
• incur or guarantee additional indebtedness or issue preferred stock;
• create or incur certain liens;
• make certain acquisitions and investments;
• redeem or prepay other debt;
• enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
• consolidate, merge or transfer all or substantially all of our assets;
• engage in transactions with affiliates;
• create unrestricted subsidiaries;
• enter into sale and leaseback transactions; and
• engage in certain business activities.
As a result of these covenants, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Our ability to comply with some of the covenants and restrictions contained in our revolving credit facility and the indentures governing our senior unsecured notes may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facility, the indentures governing our senior unsecured notes or any future indebtedness could result in an event of default under our revolving credit facility, the indentures governing our senior unsecured notes or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations.
If an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder:
• would not be required to lend any additional amounts to us;
• could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;
• may have the ability to require us to apply all of our available cash to repay these borrowings; or
• may prevent us from making debt service payments under our other agreements.
A payment default or an acceleration under our revolving credit facility could result in an event of default and an acceleration under the indentures for our senior unsecured notes. If the indebtedness under the notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under our revolving credit facility are collateralized by perfected first priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 80% of the reserve value as determined by reserve reports, and if we are unable to repay our indebtedness under the revolving credit facility, the lenders could seek to foreclose on our assets. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and capital resources.”
Our level of indebtedness may increase and reduce our financial flexibility.
As of December 31, 2012, we had no indebtedness outstanding under our revolving credit facility, $497.8 million available for future secured borrowings under our revolving credit facility and $1.2 billion outstanding in senior unsecured notes. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and capital resources-Senior secured revolving line of credit” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and capital resources-Senior unsecured notes.” In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.
Our level of indebtedness could affect our operations in several ways, including the following:
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a significant portion of our cash flows could be used to service our indebtedness;
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a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
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the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
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our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
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a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
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a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and
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a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.
A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, and borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.
In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results.
Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production ($110.3 million in receivables at December 31, 2012), which we market to energy marketing companies, refineries and affiliates, advances to joint interest parties ($2.0 million at December 31, 2012) and joint interest receivables ($99.2 million at December 31, 2012).
We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. For the year ended December 31, 2012, sales to Musket Corporation accounted for approximately 10% of our total sales. For the year ended December 31, 2011, sales to Texon L.P., Plains All American Pipeline, L.P. and Enserco Energy Inc. accounted for approximately 18%, 16% and 15%, respectively, of our total sales. For the year ended December 31, 2010, sales to Plains All American Pipeline, L.P., Texon L.P. and Whiting Petroleum Corporation accounted for approximately 28%, 19% and 11%, respectively, of our total sales. No other purchasers accounted for more than 10% of our total oil and natural gas sales for the years ended December 31, 2012, 2011 and 2010. We do not require all of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.
We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.
We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:
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recoverable reserves;
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future oil and natural gas prices and their appropriate differentials;
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development and operating costs; and
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potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems, such as, for example, groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
Significant acquisitions and other strategic transactions may involve other risks, including:
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diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
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the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;
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difficulty associated with coordinating geographically separate organizations; and
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the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be lower than we expect.
The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated net proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.
Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in the title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of proposed legislation.
President Obama’s budget proposal for fiscal year 2013 recommended the elimination of certain key United States federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities for oil and gas production, and (iv) the extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes or similar changes will be enacted or, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and gas exploration and production. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.
Risks Relating to our Common Stock
We do not intend to pay, and we are currently prohibited from paying, dividends on our common stock and, consequently, our shareholders’ only opportunity to achieve a return on their investment is if the price of our stock appreciates.
We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently prohibited from making any cash dividends pursuant to the terms of our revolving credit facility and the indentures governing our senior unsecured notes. Consequently, our shareholders’ only opportunity to achieve a return on their investment in us will be if the market price of our common stock appreciates, which may not occur, and the shareholder sells their shares at a profit. There is no guarantee that the price of our common stock will ever exceed the price that the shareholder paid.
Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our amended and restated certificate of incorporation authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
•
a classified Board of Directors, so that only approximately one-third of our directors are elected each year;
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limitations on the removal of directors; and
•
limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the Board of Directors to be acted upon at meetings of stockholders.
Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our Board of Directors.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
The information required by Item 2. is contained in Item 1. Business.
Item 3.
Item 3. Legal Proceedings
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceeding. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market for Registrant’s Common Equity. Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “OAS.”
The following table sets forth the range of high and low sales prices of our common stock for the two most recent fiscal years as reported by the NYSE:
Holders. The number of shareholders of record of our common stock was approximately 26,749 on February 22, 2013.
Dividends. We have not paid any cash dividends since our inception. Covenants contained in our revolving credit facility and the indentures governing our senior unsecured notes restrict the payment of cash dividends on our common stock. We currently intend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.
On February 28, 2013, the last sale price of our common stock, as reported on the NYSE, was $36.70 per share.
Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2012.
Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the three months ended December 31, 2012:
(1) Represent shares that employees surrendered back to us that equaled in value the amount of taxes needed for payroll tax withholding obligations upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.
Stock Performance Graph. The following performance graph and related information is “furnished” with the SEC and shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended (“Exchange Act”), except to the extent that we specifically request that such information be treated as “soliciting material” or specifically incorporate such information by reference into such a filing.
The performance graph shown below compares the cumulative total return to the Company’s common stockholders as compared to the cumulative total returns on the Standard and Poor’s 500 Index (S&P 500) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (S&P 500 O&G E&P) since the time of our IPO. The comparison was prepared based upon the following assumptions:
1. $100 was invested in our common stock at its initial public offering price of $14 per share and invested in the S&P 500 and the S&P 500 O&G E&P on June 16, 2010 at the closing price on such date; and
2. Dividends are reinvested.
Item 6.
Item 6. Selected Financial Data
Set forth below is our summary historical consolidated financial data for the years ended December 31, 2012, 2011, 2010, 2009 and 2008, and balance sheet data at December 31, 2012, 2011, 2010, 2009 and 2008. This information may not be indicative of our future results of operations, financial position and cash flows and should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary note regarding forward-looking statements.”
Overview
We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the Montana and North Dakota regions of the Williston Basin. Since our inception, we have acquired properties that provide current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken and Three Forks formations. We also operate a marketing business, OPM, that is complementary to our primary development and production activities, and a well services business, OWS, which is a separate reportable business segment. The revenues and expenses related to work performed by OPM and OWS for OPNA’s working interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.
Our use of capital for development and acquisitions allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided a foothold in a new area of interest or complemented our existing operations. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. In addition, our willingness to acquire non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis.
We built our Williston Basin leasehold acreage position in our West Williston, East Nesson and Sanish project areas through acquisitions and development activities. These acquisitions and development activities were financed with a combination of capital from private and public investors, borrowings under our revolving credit facility, cash flows provided by operating activities and proceeds from our senior unsecured notes.
Our 2012, 2011 and 2010 activities included development and exploration drilling in each of our primary project areas. Our current activities are focused on evaluating and developing our asset base, optimizing our acreage positions and evaluating potential acquisitions. Based on the reserve reports prepared by our independent reserve engineers, we had 143.3 MMBoe of estimated net proved reserves with a PV-10 of $3,244.3 million and a Standardized Measure of $2,259.9 million at December 31, 2012, 78.7 MMBoe of estimated net proved reserves with a PV-10 of $1,903.7 million and a Standardized Measure of $1,319.5 million at December 31, 2011 and 39.8 MMBoe of estimated net proved reserves with a PV-10 of $697.8 million and a Standardized Measure of $485.7 million at December 31, 2010. Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $94.68/Bbl for oil and $2.75/MMBtu for natural gas, $96.23/Bbl for oil and $4.12/MMBtu for natural gas, and $79.40/Bbl for oil and $4.38/MMBtu for natural gas for the years ended December 31, 2012, 2011 and 2010, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
Due to the geographic concentration of our oil and natural gas properties in the Williston Basin, we believe the primary sources of opportunities, challenges and risks related to our business for both the short and long-term are:
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commodity prices for oil and natural gas;
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transportation capacity;
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availability and cost of services; and
•
availability of qualified personnel.
Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.
Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations. We enter into crude oil sales contracts with purchasers who have access to crude oil transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows. Please see “Item 1. Business-Marketing, transportation and major customers.”
Our quarterly average net realized oil prices and average price differentials are shown in the table below.
(1) Realized oil prices do not include the effect of realized derivative contract settlements.
(2) Price differential compares realized oil prices to WTI crude oil index prices.
Changes in commodity prices may also significantly affect the economic viability of drilling projects as well as the economic valuation and economic recovery of oil and gas reserves. Oil prices have increased significantly since 2009. The higher commodity prices, as well as continued successes in the application of completion technologies in the Bakken formation, caused the active drilling rig count in the Williston Basin to increase to approximately 195 rigs at December 31, 2012. Although additional Williston Basin transportation takeaway capacity was added in recent years, production also increased due to the elevated drilling activity. The increased production coupled with delays in rail car arrivals and commissioning of rail loading facilities caused price differentials at times to be at the high-end of the historical average range of approximately 10% to 15% of the WTI crude oil index price in the first half of 2012. In the third quarter of 2012, differentials began to narrow, primarily due to transportation capacity additions, including expanded rail infrastructure and pipeline expansions, outpacing production growth. In the fourth quarter of 2012, these price differentials continued to narrow, and at some points crude oil produced in the Williston Basin sold at a premium to WTI crude oil index prices as a result of additional transportation capacity additions which had access to the East and West Coast refineries.
Our large concentrated acreage position potentially provides us with a multi-year inventory of drilling projects and requires some forward planning visibility for obtaining services. Our ability to develop and hold our existing undeveloped leasehold acreage is primarily dependent upon having access to drilling rigs and completion services. To ensure access to drilling rigs, we have entered into fixed-term drilling rig contracts for periods of up to three years and currently have nine drilling rigs under contract. In order to ensure the availability of completion services and the timely fracture stimulation of newly drilled wells, we formed OWS in June 2011 to provide well services on our operated wells, in addition to entering into fracturing service contracts with third party companies.
2012 Highlights
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We completed and placed on production 117 gross (95.8 net) operated Bakken and Three Forks wells during 2012, and increased average daily production by 110% to 22,469 Boe per day from 10,724 Boe per day in 2011.
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We increased estimated net proved oil and natural gas reserves at December 31, 2012 to 143.3 MMBoe, an 82% increase over year-end 2011 estimated net proved reserves. Approximately 89% of estimated net proved reserves at year-end 2012 consisted of oil and 49% were classified as proved developed.
• We grew our leasehold position to 335,383 total net acres in the Williston Basin, primarily targeting the Bakken and Three Forks formations, and increased our operated drill blocks by 37 through acreage additions and trades during 2012. In addition, we have increased our acreage that is held-by-production to 264,595 net acres as of December 31, 2012.
• As of December 31, 2012, we had nine operated rigs running.
• In 2012, OWS began providing well services to OPNA, and we had three fracturing services crews, including OWS, working full time as of December 31, 2012.
• In 2012, OPM became the first purchaser for the majority of our operated oil volumes and provided downstream gathering, transportation and marketing services to OPNA.
• In 2012, we began selling a significant amount of our crude oil production from our West Williston project area through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. As of December 31, 2012, we flowed approximately 60% of our gross operated oil production through these gathering systems. We expect to increase the gross operated oil production that will flow on these systems to over 80% by mid-year 2013 with the implementation of gathering connections in our East Nesson project area.
• In 2012, we entered into new two-way and three-way collar options, swaps and put spreads, all of which settle monthly based on the WTI crude oil index price. As of December 31, 2012, we had a total notional amount of 7,223,500 barrels that settle in 2013, 2,775,500 barrels that settle in 2014 and 201,500 barrels that settle in 2015.
• On July 2, 2012, we issued $400.0 million of 6.875% senior unsecured notes due January 15, 2023. The issuance of these notes resulted in net proceeds to us of approximately $392.4 million, which we continue to use to fund our exploration, development and acquisition program and for general corporate purposes.
• On October 2, 2012, we entered into our seventh amendment to our revolving credit facility. In connection with this amendment, the semi-annual redetermination of our borrowing base was completed, which resulted in an increase to the borrowing base of our revolving credit facility from $500 million to $750 million. However, we elected to have the lenders’ aggregate commitment remain at $500 million, which we may increase in the future to $750 million by increasing the commitment of one or more lender(s).
• At December 31, 2012, we had $239.3 million of cash, cash equivalents and short-term investments. We had no outstanding borrowings and had $2.2 million of outstanding letters of credit under our revolving credit facility.
• Our 2013 capital expenditure budget is $1,020 million, an 11% decrease from our 2012 capital expenditures of $1,148.6 million. The 2013 budget consists of:
• $897 million of drilling and completion capital for operated and non-operated wells (including expected savings from services provided by OWS);
• $43 million for constructing infrastructure to support production in our core project areas, primarily related to salt water disposal systems;
• $25 million for maintaining and expanding our leasehold position;
• $10 million for micro-seismic work, purchasing seismic data and other test work;
• $21 million for facilities and other miscellaneous E&P capital expenditures;
• $14 million for OWS; and
• $10 million for other non-E&P capital, including items such as administrative capital and capitalized interest.
Results of Operations
Revenues
Our revenues are derived from the sale of oil and natural gas production and well services and do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
The following table summarizes our revenues and production data for the periods indicated.
(1) For the year ended December 31, 2012, average sales prices for oil are calculated using total oil revenues, excluding bulk purchase sales of $1.5 million, divided by oil production.
(2) Realized prices include realized gains or losses on cash settlements for our commodity derivatives, which do not qualify for and were not designated as hedging instruments for accounting purposes.
(3) Natural gas prices include the value for natural gas and natural gas liquids.
Year ended December 31, 2012 as compared to year ended December 31, 2011
Total revenues. Our total revenues increased $356.2 million, or 108%, to $686.7 million during the year ended December 31, 2012 as compared to the year ended December 31, 2011. Our exploration and production revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 11,745 Boe per day, or 110%, to 22,469 Boe per day during the year ended December 31, 2012 as compared to the year ended December 31, 2011. The increase in average daily production sold was primarily a result of a higher number of well completions during 2012, offsetting the decline in production in wells that were producing as of December 31, 2011. Production from wells completed in our West Williston, East Nesson and Sanish project areas contributed to average daily production by approximately 8,085 Boe per day, 2,514 Boe per day and 819 Boe per day, respectively, during 2012. Average oil sales prices, without realized derivatives, decreased by $0.96/Bbl, or 1%, to an average of $85.22/Bbl for the year ended December 31, 2012 as compared to the year ended December 31, 2011. The higher production amounts sold increased revenues by $343.7 million, while lower oil and natural gas sales prices decreased revenues by $5.2 million. Well services revenues, which resulted from third-party working interest owners in OPNA’s wells, were $16.2 million for the year ended December 31, 2012. There were no well services revenues during the year ended December 31, 2011 because OWS did not commence fracturing activity until the first quarter of 2012. The remaining $1.5 million increase in total revenues was attributable to oil bulk purchase revenues related to marketing activities included in oil and gas revenues during the year ended December 31, 2012.
Year ended December 31, 2011 as compared to year ended December 31, 2010
Total revenues. Our oil and natural gas sales revenues increased $201.5 million, or 156%, to $330.4 million during the year ended December 31, 2011 as compared to the year ended December 31, 2010. Average daily production sold increased by 5,518 Boe per day, or 106%, to 10,724 Boe per day during the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in average daily production sold was primarily a result of a higher number of well completions during 2011, offsetting the decline in production in wells that were producing as of December 31, 2010. Production from wells completed in our West Williston, East Nesson and Sanish project areas contributed to average daily production by approximately 4,121 Boe per day, 936 Boe per day and 437 Boe per day, respectively, during 2011. The higher production amounts sold increased revenues by $170.8 million, and the remaining $30.7 million increase in revenues was attributable to higher oil and natural gas sales prices during the year ended December 31, 2011. Average oil sales prices, without realized derivatives, increased by $16.58/Bbl, or 24%, to an average of $86.18/Bbl for the year ended December 31, 2011 as compared to the year ended December 31, 2010.
Expenses
The following table summarizes our operating expenses for the periods indicated.
(1) For the years ended December 31, 2011 and 2010, lease operating expenses exclude marketing, transportation and gathering expenses to conform such amounts to current year classifications.
(2) During 2010, we recorded $8.7 million in stock-based compensation expense associated with C Units and discretionary stock awards granted. Stock-based compensation expense related to the amortization of restricted stock and performance share units is included in general and administrative expenses on the Consolidated Statement of Operations. See Note 9 to our audited consolidated financial statements.
Year ended December 31, 2012 compared to year ended December 31, 2011
Lease operating expenses. Lease operating expenses increased $22.2 million to $54.9 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. This increase was primarily due to the costs associated with operating an increased number of producing wells and associated produced fluid volumes as a result of our 2012 well completions. Increased costs primarily related to workovers, chemical treatments, equipment rental and fresh water injections, which have improved operational performance and minimized downtime in our wells. These cost increases were partially offset by salt water disposal activity and lower operating costs related to improved weather conditions as compared to the first half of 2011. The unit operating costs decreased from $8.36 for the year ended December 31, 2011 to $6.68 for the year ended December 31, 2012, primarily due to our increase in production of 110% outpacing our overall net increase in costs of 68%.
Well services operating expenses. The $11.8 million in well services operating expenses represents third-party working interests’ share of fracturing service costs incurred by OWS for fracturing jobs completed in 2012. There were no well services operating expenses in 2011 because OWS did not commence fracturing activity until the first quarter of 2012.
Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses includes all of our marketing, transportation and gathering for our oil production as well as bulk oil purchase costs. The $7.9 million increase period over period, or $0.79 increase per Boe, is primarily attributable to increased oil transportation costs related to OPM, which did not commence operations until late in the third quarter of 2011, combined with a $1.4 million cost for bulk oil purchases made by OPM in the first quarter of 2012, partially offset by a $0.7 million non-cash valuation adjustment on our oil pipeline imbalances. Excluding this pipeline imbalance adjustment and bulk oil purchase costs, our marketing, transportation and gathering expenses on a per Boe basis would have been $1.04 for the year ended December 31, 2012.
Production taxes. Our production taxes for the years ended December 31, 2012 and 2011 were 9.4% and 10.2%, respectively, as a percentage of oil and natural gas sales. The 2012 production tax rate was lower than the 2011 production tax rate because of the increased weighting of oil revenues in Montana, which has lower incentivized production tax rates on certain new wells for the first twelve months of production.
Depreciation, depletion and amortization (DD&A). DD&A expense increased $131.8 million to $206.7 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. The increase in DD&A expense for the year ended December 31, 2012 was primarily a result of our production increases from our 2012 well completions. The DD&A rate for the year ended December 31, 2012 was $25.14 per Boe compared to $19.16 per Boe for the year ended December 31, 2011. The higher DD&A rate was a result of increased well costs in 2012, which outpaced the increase in associated reserves. The increased well costs were a result of increases in service costs in the Williston Basin during 2011 and the first half of 2012 and the addition of infrastructure assets, primarily our salt water disposal systems.
Impairment of oil and gas properties. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2012 and 2011. During the years ended December 31, 2012 and 2011, we recorded non-cash impairment charges of $3.6 million each year for unproved properties due to leases that expired during the period and periodic assessments of unproved properties. As of December 31, 2012, we recorded a $1.8 million impairment charge related to acreage expiring in 2013 as a result of a periodic assessment because there were no plans to drill or extend the leases prior to their expiration. In determining the amount of non-cash impairment charges for such periods, we considered the application of the factors described under “Critical accounting policies and estimates-Impairment of proved properties” and “Critical accounting policies and estimates-Impairment of unproved properties.”
General and administrative. Our general and administrative expenses increased $27.8 million for the year ended December 31, 2012 from $29.4 million for the year ended December 31, 2011. Of this increase, approximately $20.3 million was due to the impact of our organizational growth on employee compensation and $6.7 million was due to the amortization of our restricted stock awards and performance share units (“PSUs”). As of December 31, 2012, we had 281 full-time employees compared to 146 full-time employees as of December 31, 2011.
Derivatives. As a result of our derivative activities, we incurred a $6.5 million net cash settlement gain for the year ended December 31, 2012 and a $3.8 million net cash settlement loss for the year ended December 31, 2011. In addition, as a result of forward oil price changes, we recognized non-cash unrealized mark-to-market derivative gains of $27.6 million and $5.4 million during the years ended December 31, 2012 and 2011, respectively.
Interest expense. Interest expense increased $40.5 million to $70.1 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. The increase was due to the interest related to our senior unsecured notes issued in February and November 2011 and July 2012. For the years ended December 31, 2012 and 2011, we incurred no borrowings under our revolving credit facility. We capitalized $3.3 million and $3.1 million of interest costs for the years ended December 31, 2012 and 2011, respectively, which will be amortized over the life of the related assets.
Income tax expense. Income tax expense for the years ended December 31, 2012 and 2011 was recorded at 37.6% and 37.1% of pre-tax net income, respectively. Our effective tax rate is expected to continue to closely approximate the statutory rate applicable to the United States and the blended state rate of the states in which we conduct business.
Year ended December 31, 2011 compared to year ended December 31, 2010
Lease operating expenses. Lease operating expenses increased $18.6 million to $32.7 million for the year ended December 31, 2011 compared to the year ended December 31, 2010. This increase was primarily due to an increased number of producing wells from our West Williston acquisitions that were completed in the fourth quarter of 2010 and to our well completions during 2011. The unit operating costs increased from $7.43 for the year ended December 31, 2010 to $8.36 for the year ended December 31, 2011, primarily due to increased costs associated with water production, salt water disposal and the continuing effects of the inclement weather during the first half of 2011.
Production taxes. Our production taxes for the years ended December 31, 2011 and 2010 were 10.2% and 10.7%, respectively, as a percentage of oil and natural gas sales. The 2011 production tax rate was lower than the 2010 production tax rate because of the increased weighting of oil revenues in Montana, which has lower incentivized production tax rates on certain new wells for the first twelve months of production. Our production taxes for the year ended December 31, 2010 were primarily for oil and natural gas sales revenue associated with properties in the North Dakota portion of our West Williston project area, which generate revenues subject to an 11.5% production tax rate.
Depreciation, depletion and amortization (DD&A). DD&A expense increased $37.1 million to $75.0 million for the year ended December 31, 2011 compared to the year ended December 31, 2010. The increase in DD&A expense for the year ended December 31, 2011 was primarily a result of our production increases and well completions during 2011. The DD&A rate for the year ended December 31, 2011 was $19.16 per Boe compared to $19.91 per Boe for the year ended December 31, 2010. The lower DD&A rate was due to the lower cost of reserve additions associated with our 2011 drilling activities.
Impairment of oil and gas properties. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2011 and 2010. During the years ended December 31, 2011 and 2010, we recorded non-cash impairment charges of $3.6 million and $12.0 million, respectively, for unproved property leases that expired during the period. In determining the amount of the non-cash impairment charges for such periods, we considered the application of the factors described under “Critical accounting policies and estimates-Impairment of proved properties” and “Critical accounting policies and estimates-Impairment of unproved properties.” As of December 31, 2011, we did not record an impairment charge with respect to any acreage expiring in 2012 based primarily on our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that would otherwise expire.
Stock-based compensation expenses. For the year ended December 31, 2010, we recorded $8.7 million of primarily non-cash charges for stock-based compensation expense associated with Oasis Petroleum Management LLC’s (“OP Management”) grant of C Units to certain of our employees in March 2010 and grant of discretionary shares of our common stock to certain of our employees who were not C Unit holders and certain contractors in the fourth quarter of 2010. Based on the characteristics of these awards, we concluded that they represented equity-type awards, and we accounted for the value of these awards as if they had been awarded by us. We used fair-value-based methods to determine the value of stock-based compensation awarded to our employees and contractors and recognized the entire amount as expense due to the immediate vesting of the awards, with no future requisite service period required by the employees. As of December 31, 2010, OP Management had distributed substantially all cash or requisite common stock to its members based on membership interests and distribution percentages. No stock-based compensation expense was recorded for the year ended December 31, 2011 related to the C Units or discretionary shares.
General and administrative. Our general and administrative expenses increased $9.7 million for the year ended December 31, 2011 from $19.7 million for the year ended December 31, 2010. Of this increase, approximately $6.5 million was due to the impact of our organizational growth on employee compensation and $2.4 million was due to the amortization of our restricted stock awards. As of December 31, 2011, we had 146 full-time employees compared to 62 full-time employees as of December 31, 2010.
Derivatives. As a result of our derivative activities, we incurred net cash settlement losses of $3.8 million and $0.1 million for the years ended December 31, 2011 and 2010, respectively. In addition, as a result of forward oil price changes, we recognized a $5.4 million non-cash unrealized mark-to-market derivative gain during the year ended December 31, 2011 and a $7.5 million non-cash unrealized mark-to-market derivative loss during the year ended December 31, 2010.
Interest expense. Interest expense increased $28.3 million to $29.6 million for the year ended December 31, 2011 compared to the year ended December 31, 2010. The increase was due to the interest related to our 7.25% and 6.5% senior unsecured notes issued in February and November 2011, respectively. For the year ended December 31, 2011, we incurred no borrowings under our revolving credit facility compared to a weighted average debt balance of $15.3 million for the year ended December 31, 2010. We capitalized $3.1 million of interest costs for the year ended December 31, 2011, which will be amortized over the life of the related assets. No interest costs were capitalized for the year ended December 31, 2010.
Income tax expense. Income tax expense increased $3.8 million to $46.8 million for the year ended December 31, 2011 compared to the year ended December 31, 2010. For the year ended December 31, 2011, our effective tax rate was 37.1% compared to 323.8% for the year ended December 31, 2010. Prior to our corporate reorganization in June 2010, no provision for federal or state income taxes was recorded, as we were a limited liability company and not subject to federal or state income tax. In 2010, we recorded an estimated net deferred tax expense of $35.6 million to recognize a deferred tax liability for the initial book and tax basis differences. Prospectively, we expect our annual effective tax rate to be between 37% and 39%. Our effective tax rate for 2011 differs from the federal statutory rate of 35% due to the effect of state income taxes. For 2010, our effective tax rate differs from the federal statutory rate of 35% due to the effect of the initial deferred tax expense, certain non-deductible IPO-related costs, non-deductible stock-based compensation expenses and state income taxes.
Liquidity and capital resources
Our primary sources of liquidity as of the date of this report have been proceeds from our senior unsecured notes, cash flows from operations and historically, borrowings under our revolving credit facility and capital from private and public investors. Our primary use of capital has been for the development and acquisition of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.
Our cash flows for the years ended December 31, 2012, 2011 and 2010 are presented below:
Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in oil prices on a portion of our production, thereby mitigating our exposure to oil price declines, but these transactions may also limit our cash flow in periods of rising oil prices. For additional information on the impact of changing prices on our financial position, see “Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.
Commodity price exposure risk. We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our future production.
We utilize derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2012, we utilized two-way and three-way collar options, swaps and put spreads to reduce the volatility of oil prices on a significant portion of our future expected oil production. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be WTI plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A put spread is a combination of a purchased put and a sold put, and in this case does not include a sold call, allowing the volumes under this contract to have no established maximum price (ceiling). A swap is a sold call and a purchased put established at the same price (both ceiling and floor).
We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement.
The following is a summary of our derivative contracts as of December 31, 2012:
Interest rate risk. At December 31, 2012, we had $400.0 million of senior unsecured notes at a fixed cash interest rate of 7.25% per annum, $400.0 million of senior unsecured notes at a fixed cash interest rate of 6.875% and $400.0 million of senior unsecured notes at a fixed cash interest rate of 6.5% per annum outstanding. During the year ended December 31, 2012, we had no indebtedness outstanding under our revolving credit facility. We do not currently, but may in the future utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issued under our revolving credit facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
While we do not require all of our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. Several of our significant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.
As permitted under our investments policy, we may purchase commercial paper instruments from high credit quality counterparties. These counterparties may include issuers in a variety of industries including the domestic and foreign financial sector. This risk is managed by our investment policy including minimum credit ratings thresholds and maximum counterparty exposure values. Although we do not anticipate any of our commercial paper issuers failing to pay us upon maturity, we take a risk in purchasing the commercial paper instruments available in the marketplace. If an issuer fails to repay us at maturity from commercial paper proceeds, it could take a significant amount of time to recover a portion of or all of the assets originally invested. Our commercial paper balance was $15.0 million at December 31, 2012.
In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. The counterparties on our derivative instruments currently in place are lenders under our revolving credit facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other lenders under our revolving credit facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the hedged volumes placed under individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. We had a net derivative asset position of $24.0 million and a net derivative liability position of $1.4 million at December 31, 2012.
Item 8.
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Oasis Petroleum Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in stockholders’/members’ equity and of cash flows present fairly, in all material respects, the financial position of Oasis Petroleum Inc. and its subsidiaries (the “Company”) at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our audits (which were integrated audits in 2011 and 2012). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 11, the Company has restated its 2010 consolidated financial statements to correct an error in loss per share and weighted average shares outstanding for the year ended December 31, 2010.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2013
Oasis Petroleum Inc.
Consolidated Balance Sheet
The accompanying notes are an integral part of these consolidated financial statements.
Oasis Petroleum Inc.
Consolidated Statement of Operations
(1) 2010 restated (see Note 11).
The accompanying notes are an integral part of these consolidated financial statements.
Oasis Petroleum Inc.
Consolidated Statement of Changes in Stockholders’/Members’ Equity
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
Oasis Petroleum Inc.
Consolidated Statement of Cash Flows
The accompanying notes are an integral part of these consolidated financial statements.
Oasis Petroleum Inc.
Notes to Consolidated Financial Statements
1. Organization and Operations of the Company
Organization
Oasis Petroleum Inc. (“Oasis” or the “Company”) was formed on February 25, 2010, pursuant to the laws of the State of Delaware, to become a holding company for Oasis Petroleum LLC (“OP LLC”), the Company’s predecessor, which was formed as a limited liability company on February 26, 2007 by certain members of the Company’s senior management team and through investments made by Oasis Petroleum Management LLC (“OP Management”) and certain private equity investors. OP Management, a Delaware limited liability company, was formed in February 2007 to allow Company employees to become indirect investors in OP LLC. In May 2007, the Company formed Oasis Petroleum North America LLC (“OPNA”), a Delaware limited liability company, to conduct its domestic oil and natural gas exploration and production activities. In April 2008, the Company formed Oasis Petroleum International LLC (“OPI”), a Delaware limited liability company, to conduct business development activities outside of the United States of America. As of December 31, 2012, OPI had no business activities or material assets.
A corporate reorganization occurred concurrently with the completion of the Company’s initial public offering (“IPO”) of its common stock on June 22, 2010. The Company sold 30,370,000 shares and OAS Holding Company LLC (“OAS Holdco”), the selling stockholder, sold 17,930,000 shares of the Company’s common stock, in each case, at $14.00 per share. After deducting underwriting discounts and commissions of approximately $25.5 million, the Company received net proceeds of $399.7 million. The selling stockholder received aggregate net proceeds of approximately $236.0 million. The Company did not receive any proceeds from the sale of the shares by OAS Holdco. As a part of this corporate reorganization, the Company acquired all of the outstanding membership interests in OP LLC in exchange for shares of the Company’s common stock. The Company’s business continues to be conducted through OP LLC, as a wholly owned subsidiary.
In June 2011, the Company formed Oasis Well Services LLC (“OWS”), a Delaware limited liability company, to provide well services to OPNA. In July 2011, the Company formed Oasis Petroleum Marketing LLC (“OPM”), a Delaware limited liability company, to provide marketing services to OPNA.
Nature of Business
The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the Williston Basin. The Company’s assets, which consist of proved and unproved oil and natural gas properties, are located primarily in the Montana and North Dakota areas of the Williston Basin and are owned by OPNA. The Company also operates a marketing business (OPM) that is complementary to its primary development and production activities, and a well services business (OWS), which is a separate reportable business segment.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Company include the accounts of Oasis and its wholly owned subsidiaries: OP LLC, OPNA, OPI, OWS and OPM. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany transactions have been eliminated in consolidation. Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income (loss).
Use of Estimates
Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.
As an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.
Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depletion, depreciation and amortization expense, dismantlement and abandonment costs, and impairment expense.
Cash Equivalents and Short-Term Investments
The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents. The Company classifies all such investments with original maturity dates greater than 90 days as held-to-maturity securities based on management’s intentions to hold the investments to their maturity dates.
Accounts Receivable
Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. No allowance for doubtful accounts was recorded for the years ended December 31, 2012 and 2011.
Inventory
Equipment and materials consist primarily of tubular goods, well equipment to be used in future drilling or repair operations and well fracturing equipment, chemicals and proppant, all of which are stated at the lower of cost or market with cost determined on an average cost method. Crude oil inventories include oil in tank and line fill and are valued at the lower of average cost or market value. Inventory consists of the following:
Joint Interest Partner Advances
The Company participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital intensive nature of oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid.
Property, Plant and Equipment
Proved Oil and Gas Properties
Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.
The provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.
Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate for an entire field, in which case a gain or loss is recognized currently. In November 2011, the Company sold its remaining interests in non-core oil and natural gas producing properties located in the Barnett shale in Texas and interests in other properties for an aggregate $2.2 million in cash. The Company recognized a loss of $0.2 million from these divestures. No gain or loss for the sale of oil and natural gas properties was recorded for the years ended December 31, 2012 or 2010.
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further discussed in Note 3 - Fair Value Measurements. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2012, 2011 and 2010.
Unproved Oil and Gas Properties
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment of oil and gas properties in the Consolidated Statement of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties:
•
the remaining amount of unexpired term under its leases;
•
its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;
•
its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
•
its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
•
its evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations by the Company or by other operators in areas adjacent to or near the Company’s unproved properties.
As a result of expiring unproved property leases and periodic assessments of unproved properties, the Company recorded non-cash impairment charges of $3.6 million for each of the years ended December 31, 2012 and 2011 and $12.0 million for the year ended December 31, 2010.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Capitalized Interest
The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. The Company capitalized $3.3 million and $3.1 million of interest costs for the years ended December 31, 2012 and 2011, respectively. These amounts will be amortized over the life of the related assets. No interest costs were capitalized for the year ended December 31, 2010.
Other Property and Equipment
Furniture, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets. The Company uses estimated lives of three to seven years for furniture and equipment, twenty years for buildings, and the remaining lease term for leasehold improvements. The cost of assets disposed of and the associated accumulated depletion, depreciation and amortization are removed from the Company’s Consolidated Balance Sheet with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statement of Operations.
Exploration Expenses
Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.
Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for the near future or the necessary approvals are actively being sought.
Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented:
As of December 31, 2012, the Company had no exploratory well costs that were capitalized for a period greater than one year.
Deferred Financing Costs
The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in deferred costs and other assets on the Company’s Consolidated Balance Sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.
Asset Retirement Obligations
In accordance with the Financial Accounting Standard Board’s (“FASB”) authoritative guidance on asset retirement obligations (“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in the Company’s Consolidated Statement of Operations.
The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 3 - Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Revenue Recognition
Oil and gas revenue from the Company’s interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of the Company’s production is sold to purchasers under short-term (less than twelve months) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, the Company sells the majority of its production soon after it is produced at various locations. As a result, the Company maintains a minimum amount of product inventory in storage.
Well services revenue is recognized when well completion services have been performed or related products have been delivered. OWS provides wells services and sells related products exclusively to OPNA. The revenues related to OPNA’s working interests are eliminated in consolidation, and only the revenues related to other working interest owners in OPNA’s wells are included in the Company’s Consolidated Statement of Operations.
Revenues and Production Taxes Payable
The Company calculates and pays taxes and royalties on oil and natural gas in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements.
Concentrations of Market and Credit Risk
The future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.
The Company operates in the exploration, development and production sector of the oil and gas industry. The Company’s receivables include amounts due from purchasers of its oil and natural gas production and amounts due from joint venture partners for their respective portions of operating expenses and exploration and development costs. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. A portion of our trade receivables are collateralized.
The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.
Risk Management
The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2012, the Company utilized two-way and three-way collar options, swaps and put spreads to reduce the volatility of oil prices on a significant portion of the Company’s future expected oil production (see Note 4 - Derivative Instruments).
The Company records all derivative instruments on the Consolidated Balance Sheet as either assets or liabilities measured at their estimated fair value. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Realized gains and losses from the settlement of commodity derivative instruments and unrealized gains and losses from valuation changes in the remaining unsettled commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statement of Operations. Unrealized gains are included in current and noncurrent assets and unrealized losses are included in current and noncurrent liabilities on the Consolidated Balance Sheet, respectively. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows.
Derivative financial instruments that hedge the price of oil are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has derivatives in place with six counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from its counterparties. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.
The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Company’s revolving credit facility (see Note 7- Long-Term Debt). As of December 31, 2012, the Company had limitations under its revolving credit facility, including a provision limiting the total amount of production that may be hedged by the Company to 110% of Current Production (as defined in the revolving credit facility) for the period from 1 to 12 months, 100% of Current Production for the period from 13 to 24 months, 75% of Current Production for the period from 25 to 36 months, and 50% of Current Production for the period from 37 to 60 months after the date of each derivative. As of December 31, 2012, the Company was in compliance with these limitations.
Environmental Costs
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
Stock-Based Compensation
Restricted Stock Awards
The Company has granted restricted stock awards to employees and directors under its 2010 Long-Term Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. As of December 31, 2012, the Company assumed no annual forfeiture rate because of the Company’s limited forfeiture history for this type of award. Stock-based compensation expense recorded for restricted stock awards is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.
Any excess tax benefit arising from the Company’s stock-based compensation plan is recognized as a credit to additional paid-in-capital when realized and is calculated as the amount by which the tax deduction received exceeds the deferred tax asset associated with the recorded stock-based compensation expense. As of December 31, 2012, the excess tax deduction related to stock-based compensation was $2.7 million. Since the Company is in a net operating loss position for tax purposes, none of the excess tax deduction was reflected in additional paid-in-capital. Pursuant to GAAP, the Company’s deferred tax asset related to net operating loss carryforward is net of the unrealized tax benefit from stock-based compensation.
Performance Share Units
The Company recognizes compensation expense for its performance share units (“PSUs”) granted to its officers under its 2010 Long-Term Incentive Plan. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the performance period, which is generally the vesting period. The fair value of the PSUs is based on the calculation derived from a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probable assessment. Any change in inputs or number of inputs to this calculation could impact the valuation and thus the stock-based compensation expense recognized. Stock-based compensation expense recorded for PSUs is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.
Treasury Stock
Treasury stock shares represent shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards. The Company includes the withheld shares as treasury stock on its Consolidated Balance Sheet and separately pays the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of the Company’s common stock and are accounted for at cost. The Company does not have a publicly announced program to repurchase shares of its common stock.
Income Taxes
The Company’s provision for taxes includes both federal and state taxes. The Company records its federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows.
The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability for the years ended December 31, 2012 and 2011.
Fair Value of Financial and Non-Financial Instruments
The carrying value of cash and cash equivalents, accounts receivable, accounts payable and other payables approximate their respective fair market values due to their short-term maturities. The Company’s derivative instruments and asset retirement obligations are also recorded on the Consolidated Balance Sheet at amounts which approximate fair market value. See Note 3 - Fair Value Measurements.
Recent Accounting Pronouncements
Intangible Assets
In July 2012, the FASB issued Accounting Standards Update No. 2012-02, Intangibles - Goodwill and Other - Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). The objective of ASU 2012-02 is to reduce the cost and complexity of performing an impairment test for indefinite-lived intangible assets by permitting an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired, as a basis for determining whether it is necessary to perform a quantitative impairment test. ASU 2012-02 is effective for interim and annual reporting periods beginning after September 15, 2012. The Company has adopted this new guidance, which did not have any impact on its financial position, cash flows or results of operations.
3. Fair Value Measurements
In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis.
As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.
The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:
Level 1 - Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 - Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.
Financial Assets and Liabilities
As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:
The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Consolidated Balance Sheet at December 31, 2012 and 2011. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identified the money market funds as Level 1 instruments due to the fact that the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments.
The Level 2 and Level 3 instruments presented in the tables above consist of oil collars, swaps and puts. The fair values of the Company’s oil collars, swaps and puts are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. The third-party preparer performs its independent valuation using an options pricing model similar to Black-Scholes. The significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. However, the Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. The determination of the fair values also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculated the credit adjustment for derivatives in an asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a liability position is based on the Company’s market credit spread. Based on these calculations, the Company recorded a downward adjustment to the fair value of its net derivative asset in the amount of $29 thousand at December 31, 2012 and a downward adjustment to the fair value of its net derivative liability in the amount of $0.3 million at December 31, 2011.
The Company has adopted the FASB’s authoritative guidance amending certain accounting and disclosure requirements related to fair value measurements. The guidance clarifies and modifies some fair value measurement principles under GAAP, including a change in the valuation premise and the application of premiums and discounts, and contains some new disclosure requirements. The guidance had no impact on the Company’s financial position, cash flows or results of operations for the year ended December 31, 2012.
The following table presents a reconciliation of the changes in fair value of the derivative instruments classified as Level 3 in the fair value hierarchy for the years presented.
(1) During the year ended December 31, 2012, the inputs used to value the Company’s commodity derivative instruments were directly or indirectly observable and those contracts were transferred to Level 2.
Fair Value of Other Financial Instruments
The Company’s financial instruments, including certain cash and cash equivalents, short-term investments, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. At December 31, 2012, the Company’s cash equivalents and short-term investments were all Level 1 assets. The carrying amount of the Company’s long-term debt (senior unsecured notes due 2019, 2021 and 2023 - see Note 7) reported in the Consolidated Balance Sheet at December 31, 2012 is $1,200.0 million with a fair value of $1,284.0 million. The Company’s senior unsecured notes are publicly traded and therefore categorized as a Level 1 liability.
Nonfinancial Assets and Liabilities
Asset retirement obligations. The carrying amount of the Company’s ARO in the Consolidated Balance Sheet at December 31, 2012 is $23.2 million (see Note 8 - Asset Retirement Obligations). The Company determines the ARO by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Impairment. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such amounts to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. No impairment charges on proved oil and natural gas properties were recorded for the year ended December 31, 2012, 2011 or 2010.
4. Derivative Instruments
The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2012, the Company utilized two-way and three-way collar options, swaps, and put spreads to reduce the volatility of oil prices on a significant portion of the Company’s future expected oil production. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX West Texas Intermediate (“WTI”) crude oil index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A put spread is a combination of a purchased put and a sold put, and in this case does not include a sold call, allowing the volumes under this contract to have no established maximum price (ceiling). A swap is a sold call and a purchased put established at the same price (both ceiling and floor).
All derivative instruments are recorded on the Consolidated Balance Sheet as either assets or liabilities measured at their fair value (see Note 3 - Fair Value Measurements). Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value, both realized and unrealized, are recognized in the other income (expense) section of the Company’s Consolidated Statement of Operations as a gain or loss on derivative instruments. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows.
As of December 31, 2012, the Company had the following outstanding commodity derivative contracts, all of which settle monthly based on the WTI crude oil index price:
The following table summarizes the location and fair value of all outstanding commodity derivative contracts recorded in the Consolidated Balance Sheet for the periods presented:
The following table summarizes the location and amounts of realized and unrealized gains and losses from the Company’s commodity derivative contracts for the periods presented:
5. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment:
Included in the Company’s proved oil and gas properties are asset retirement costs of $20.7 million and $11.4 million at December 31, 2012 and 2011, respectively.
Asset impairments. As discussed in Note 2, as a result of expiring leases and periodic assessments of unproved properties, the Company recorded non-cash impairment charges on its unproved oil and gas properties of $3.6 million for each of the years ended December 31, 2012 and 2011 and $12.0 million for the year ended December 31, 2010. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2012, 2011, and 2010.
Acquisitions. During the fourth quarter of 2010, the Company acquired approximately 16,700 net acres of land in Roosevelt County, Montana and approximately 10,000 net leasehold acres primarily located in Richland County, Montana for $52.3 million and $30.1 million, respectively. This acreage is part of the West Williston project area. Based on the FASB’s authoritative guidance, neither acquisition qualified as a business combination. The Company did not have any significant asset acquisitions for the years ended December 31, 2012 and 2011.
6. Accrued Liabilities
The Company’s accrued liabilities consist of the following:
In addition, the Company had revenue suspense of $30.0 million, production taxes payable of $11.6 million and royalties payable of $27.8 million included in revenues and production taxes payable on the Consolidated Balance Sheet for the year ended December 31, 2012. For the year ended December 31, 2011, the Company had revenue suspense of $9.5 million, production taxes payable of $5.7 million and royalties payable of $3.2 million included in revenues and production taxes payable on the Consolidated Balance Sheet.
7. Long-Term Debt
Senior unsecured notes. On July 2, 2012, the Company issued $400.0 million of 6.875% senior unsecured notes due January 15, 2023 (the “2023 Notes”). During 2011, the Company issued $400.0 million of 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”) and $400.0 million of 6.5% senior unsecured notes due November 1, 2021 (the “2021 Notes”, and together with the 2023 Notes and the 2019 Notes, the “Notes”). Interest on the Notes is payable semi-annually in arrears. The issuance of these Notes resulted in aggregate net proceeds to the Company of approximately $1,175.8 million, including $392.4 million on July 2, 2012 for the 2023 Notes and $783.4 during the year ended December 31, 2011 for the 2019 Notes and the 2021 Notes. The Company has used the proceeds from the Notes to fund its exploration, development and acquisition program and for general corporate purposes. The Notes are guaranteed on a senior unsecured basis by the Company’s material subsidiaries (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions, as follows:
• in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a restricted subsidiary of the Company;
• in connection with any sale or other disposition of the capital stock of that Guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a restricted subsidiary of the Company, such that, immediately after giving effect to such transaction, such Guarantor would no longer constitute a subsidiary of the Company;
• if the Company designates any restricted subsidiary that is a Guarantor to be an unrestricted subsidiary in accordance with the indenture;
• upon legal defeasance or satisfaction and discharge of the indenture; or
• upon the liquidation or dissolution of a Guarantor, provided no event of default occurs under the indentures as a result thereof.
The Notes were issued under indentures containing provisions that are substantially the same, as amended and supplemented by supplemental indentures (collectively the “Indentures”), among the Company, the Guarantors and U.S. Bank National Association, as trustee (the “Trustee”). The Company has certain options to redeem up to 35% of the Notes at a certain redemption price based on a percentage of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to certain dates, the Company has the option to redeem some or all of the Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The Company estimates that the fair value of these options is immaterial at December 31, 2012 and 2011.
The Indentures restrict the Company’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to certain exceptions and qualifications. If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indentures) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants.
The Indentures contain customary events of default, including:
• default in any payment of interest on any Note when due, continued for 30 days;
• default in the payment of principal or premium, if any, on any Note when due;
• failure by the Company to comply with its other obligations under the Indentures, in certain cases subject to notice and grace periods;
• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries (as defined in the Indentures) in the aggregate principal amount of $10.0 million or more;
• certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary (as defined in the Indentures) or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary;
• failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary to pay certain final judgments aggregating in excess of $10.0 million within 60 days; and
• any guarantee of the Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.
Senior secured revolving line of credit. OP LLC, as parent, and OPNA, as borrower, entered into a credit agreement dated June 22, 2007 (as amended and restated, the “Amended Credit Facility”). The Amended Credit Facility is restricted to the borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. Borrowings under the Amended Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including mortgage liens on oil and natural gas properties having at least 80% of the reserve value as determined by reserve reports. On April 3, 2012, the Company entered into its sixth amendment to its Amended Credit Facility (the “Sixth Amendment”). In connection with this amendment, the semi-annual redetermination of the borrowing base was completed on April 3, 2012, which resulted in the borrowing base of the Amended Credit Facility increasing from $350 million to $500 million. The Sixth Amendment added two new lenders to the bank group. Effective April 20, 2012, the Company executed an agreement consenting to the resignation of BNP Paribas as the administrative agent and a lender under the Amended Credit Facility. Wells Fargo was appointed successor administrative agent and assumed the credit commitment of BNP Paribas. BNP Paribas remains as a counterparty for the Company’s commodity derivative instruments. On June 25, 2012, the Company’s lenders waived the mandatory reduction of the Company’s borrowing base that otherwise would have occurred as a result of the Company’s issuance of the 2023 Notes in July 2012. On October 2, 2012, the Company entered into its seventh amendment to its Amended Credit Facility (the “Seventh Amendment”). In connection with this amendment, the semi-annual redetermination of the Company’s borrowing base was completed on October 2, 2012, which resulted in an increase to the borrowing base of its Amended Credit Facility from $500 million to $750 million. However, the Company elected to have the lenders’ aggregate commitment remain at $500 million. The Seventh Amendment provides that the Company may increase its aggregate commitment from $500 million to $750 million by increasing the commitment of one or more lender(s). The Seventh Amendment also added a requirement that the Company maintain a ratio of consolidated EBITDAX (as defined in the Amended Credit Facility) to consolidated Interest Expense (as defined in the Amended Credit Facility) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter. This covenant replaced the Total Net Debt (as defined in the Amended Credit Facility) to consolidated EBITDAX ratio covenant. All other terms and conditions of the Amended Credit Facility remained the same, including the October 6, 2016 maturity date and the $1 billion senior secured revolving line of credit.
Borrowings under the Amended Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a London interbank offered rate (“LIBOR”) loan or a domestic bank prime interest rate loan (defined in the Amended Credit Facility as an Alternate Based Rate or “ABR” loan). As of December 31, 2012, any outstanding LIBOR and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table:
An ABR loan may be repaid at any time before the scheduled maturity of the Amended Credit Facility upon the Company providing advance notification to the lenders under the Amended Credit Facility (the “Lenders”). Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a LIBOR-based loan upon providing advance notification to the Lenders. The minimum available loan term is one month and the maximum loan term is six months for LIBOR-based loans. Interest for LIBOR loans is paid upon maturity of the loan term. Interim interest is paid every three months for LIBOR loans that have loan terms greater than three months in duration. At the end of a LIBOR loan term, the Amended Credit Facility allows the Company to elect to repay the borrowing, continue a LIBOR loan with the same or a differing loan term or convert the borrowing to an ABR loan.
On a quarterly basis, the Company also pays a 0.375% (as of December 31, 2012) annualized commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.
As of December 31, 2012, the Amended Credit Facility contained covenants that included, among others:
• a prohibition against incurring debt, subject to permitted exceptions;
• a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;
• a prohibition against making investments, loans and advances, subject to permitted exceptions;
• restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted exceptions;
• restrictions on merging and selling assets outside the ordinary course of business;
• restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;
• a provision limiting oil and natural gas derivative financial instruments;
• a requirement that the Company maintain a ratio of consolidated EBITDAX to consolidated Interest Expense of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter; and
• a requirement that the Company maintain a Current Ratio (as defined in the Amended Credit Facility) of consolidated current assets (with exclusions as described in the Amended Credit Facility) to consolidated current liabilities (with exclusions as described in the Amended Credit Facility) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.
The Amended Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declare all amounts outstanding under the Amended Credit Facility to be immediately due and payable.
As of December 31, 2012, the Company had no borrowings and $2.2 million of outstanding letters of credit issued under the Amended Credit Facility, resulting in an unused borrowing base capacity of $497.8 million. The Company was in compliance with the financial covenants of the Amended Credit Facility as of December 31, 2012.
Deferred financing costs. As of December 31, 2012, the Company had $23.5 million of deferred financing costs related to the Amended Credit Facility and the senior unsecured notes. The deferred financing costs are included in deferred costs and other assets on the Company’s Consolidated Balance Sheet at December 31, 2012 and are being amortized over the respective terms of the Amended Credit Facility and the senior unsecured notes. The amortization of these deferred financing costs is included in interest expense on the Company’s Consolidated Statement of Operations.
8. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO during the years ended December 31, 2012 and 2011:
9. Stock-Based Compensation
Restricted stock awards. The Company has granted restricted stock awards to employees and directors under its 2010 Long-Term Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. As of December 31, 2012, the Company assumed no annual forfeiture rate because of the Company’s limited forfeiture history for this type of award.
The following table summarizes information related to restricted stock held by the Company’s employees and directors at December 31, 2012:
Stock-based compensation expense recorded for restricted stock awards for the years ended December 31, 2012, 2011, and 2010 was approximately $10.2 million, $3.7 million and $1.2 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. Unrecognized expense as of December 31, 2012 for all outstanding restricted stock awards was $17.2 million and will be recognized over a weighted average period of 2.2 years. The fair value of awards vested for the year ended December 31, 2012 was $11.7 million.
Performance share units. On July 30, 2012, the Company’s Board of Directors approved grants of PSUs to officers of the Company pursuant to the Company’s 2010 Long Term Incentive Plan. The PSUs are awards of restricted stock units, and each PSU that is earned represents the right to receive one share of the Company’s common stock.
The PSUs are subject to a designated three-year initial performance period beginning on August 1, 2012 and ending on July 31, 2015. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group. Depending on the Company’s performance relative to the defined peer group, an award recipient will earn between 0% and 200% of the initial PSUs granted. If less than 200% of the initial PSUs granted are earned at the end of the initial performance period, then the performance period will be extended to July 16, 2016 to give the recipient the opportunity to earn up to an aggregate of 200% of the initial PSUs granted.
The following table summarizes information related to PSUs held by the Company’s officers at December 31, 2012:
The Company accounted for these PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The fair value of these PSUs is recognized on a straight-line basis over the performance period. As it is probable that a portion of the awards will be earned during the extended performance period, the grant date fair value will be amortized over four years. However, if 200% of the initial PSUs granted are earned at the end of the initial performance period, then the remaining compensation expense will be accelerated in order to be fully recognized over three years. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.
The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, risk-free rate, volatility and correlation coefficients. The risk-free rate is the U.S. Treasury rate on the date of grant. The initial value is the average of the volume weighted average prices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility is the standard deviation of the average percentage in stock price over a historical two-year period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data. No forfeiture rate is assumed for these types of awards.
The following assumptions were used for the Monte Carlo model to value the stock-based compensation expense of the PSUs granted during 2012:
Stock-based compensation expense recorded for these PSUs for the year ended December 31, 2012 was $0.4 million and is included in general and administrative expenses on the Consolidated Statement of Operations. Unrecognized expense as of December 31, 2012 for all outstanding PSUs was $3.6 million and will be recognized over a remaining period of 3.6 years. No stock-based compensation expense was recorded for the years ended December 31, 2011 and 2010 related to the PSUs as the Company had not issued PSUs prior to July 2012.
Class C common unit interests. In March 2010, the Company recorded a $5.2 million stock-based compensation charge associated with OP Management’s grant of 1.0 million Class C common unit interests (“C Units”) to certain employees of the Company. The C Units were granted on March 24, 2010 to individuals who were employed by the Company as of February 1, 2010, and who were not executive officers or key employees with an existing capital investment in OP Management (“Oasis Petroleum Management LLC Capital Members”). All of the C Units vested immediately on the grant date, and based on the characteristics of the C Units awarded to employees, the Company concluded that the C Units represented an equity-type award and accounted for the value of this award as if it had been awarded by the Company.
The C Units were membership interests in OP Management and not direct interests in the Company. The C Units were non-transferable and had no voting power. As of December 31, 2010, OP Management had distributed substantially all cash or requisite common stock to its members based on membership interests and distribution percentages. OP Management was dissolved in 2011.
In accordance with the FASB’s authoritative guidance for share-based payments, the Company used a fair-value-based method to determine the value of stock-based compensation awarded to its employees and recognized the entire grant date fair value of $5.2 million as stock-based compensation expense on the Consolidated Statement of Operations due to the immediate vesting of the awards with no future requisite service period required of the employees.
The Company used a probability weighted expected return method to evaluate the potential return and associated fair value allocable to the C Unit shareholders using selected hypothetical future outcomes (continuing operations, private sale of the Company, and an IPO). Approximately 95% of the fair value allocated to the C Unit shareholders came from the IPO scenario. The IPO fair value of the C Units awarded to the Company’s employees was estimated on the date of the grant using a Black-Scholes option-pricing model with the assumptions described below.
The exercise price of the option used in the option-pricing model was set equal to the maximum value of OP Management’s current capital investment in the Company as that value must be returned to Oasis Petroleum Management LLC Capital Members before distributions were made to the C Unit shareholders. Since the Company was not a public entity on the grant date, it did not have historical stock trading data that could be used to compute volatilities associated with certain expected terms; therefore, the expected volatility value of 60% was estimated based on an average of volatilities of similar sized oil and gas companies with operations in the Williston Basin whose common stocks were publicly traded. The allocable fair value to the C Units assumed a timing of four years based on a future potential secondary offering or distribution of common stock of the Company. The OAS Holdco agreement between its members required a complete distribution of all remaining shares held by OAS Holdco by 2014, the fourth year following the year of the IPO. The 2.08% risk-free rate used in the pricing model was based on the U.S. Treasury yield for a government bond with a maturity equal to the time to liquidity of four years. The Company did not estimate forfeiture rates due to the immediate vesting of the award and did not estimate future dividend payments as it did not expect to declare or pay dividends in the foreseeable future.
Discretionary stock awards. During the fourth quarter of 2010, the Company recorded a $3.5 million stock-based compensation charge primarily associated with OP Management granting discretionary shares of the Company’s common stock to certain of the Company’s employees who were not C Unit holders and certain contractors. Based on the characteristics of these awards, the Company concluded that they represented an equity-type award and accounted for the value of these awards as if they had been awarded by the Company. The fair value of these awards was based on the value of the Company’s common stock on the date of grant. All of these awards vested immediately on the grant date with no future requisite service period required of the employees or contractors.
Stock-based compensation expense recorded for the C Units and discretionary stock awards for the year ended December 31, 2010 was $8.7 million. As the awards vested immediately, there was no unrecognized stock-based compensation expense as of December 31, 2012 related to these awards. No stock-based compensation expense was recorded for the years ended December 31, 2012 and 2011 related to the C Units or discretionary shares.
10. Income Taxes
The Company’s income tax expense consists of the following:
Prior to its corporate reorganization in connection with the IPO (see Note 1), the Company was a limited liability company and not subject to federal or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company’s equity holders were responsible for income tax on the Company’s profits. In connection with the closing of the Company’s IPO, the Company merged into a corporation and became subject to federal and state income taxes. The Company’s book and tax basis in assets and liabilities differed at the time of the corporate reorganization due primarily to different cost recovery periods utilized for book and tax purposes for the Company’s oil and natural gas properties.
In 2012 and 2011, the Company’s effective tax rate differs from the federal statutory rate of 35% primarily due to state income taxes. In 2010, the Company recorded an estimated net deferred tax expense of $35.6 million to recognize a deferred tax liability for the initial book and tax basis differences. The Company’s 2010 effective tax rate differs from the federal statutory rate of 35% due to the initial deferred tax expense and certain non-deductible IPO-related costs that occurred in 2010 coupled with state income taxes and non-deductible stock-based compensation expenses.
The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate for the years ended December 31, 2012, 2011 and 2010, respectively, is set forth below:
Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2012 and 2011, respectively, were as follows:
The Company generated a federal net operating tax loss of $7.7 million for the year ended December 31, 2012, and paid $7 thousand of current income taxes. The net operating loss carryforwards consist of $39.9 million of federal net operating loss carryforwards, which expire between 2030 and 2032 and $25.6 million of state net operating loss carryforwards, which expire between 2017 and 2032. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not. When the future utilization of some portion of the carryforwards is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Management believes that the Company’s taxable temporary differences and future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expiration.
Pursuant to authoritative guidance, the Company’s $13.9 million deferred tax asset related to net operating loss carryforwards is net of $1.0 million of unrealized excess tax benefits related to $2.7 million of stock-based compensation that has not yet been realized.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2012, the Company had no unrecognized tax benefits. With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in the Consolidated Statement of Operations. The Company files income tax returns in the U.S. federal jurisdiction and in North Dakota, Montana and Texas. The Company’s income tax returns have not been audited by the IRS or any state jurisdiction. Its statute of limitation for the year ended December 31, 2012 will expire in 2016. The Company’s earliest open year in its key jurisdictions is 2010 for both the U.S. federal jurisdiction and various U.S. states.
The current portion of the Company’s net deferred taxes was a liability of $4.6 million at December 31, 2012 and an asset of $3.2 million at December 31, 2011.
11. Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, unless their effect is anti-dilutive.
The Company’s loss per share for the year ended December 31, 2010 was restated to correct the net loss attributable to common stockholders from $29.7 million to $28.1 million and to correct the basic and diluted weighted average common shares outstanding from 48.4 million to 92.0 million shares, which collectively decreased the net loss from $0.61 per share to $0.31 per share. The loss per share calculation was incorrectly calculated by dividing net loss attributable to common stockholders for the full year ended December 31, 2010 by the weighted average shares outstanding for such period, rather than by dividing net loss attributable to common stockholders for the period from June 22, 2010, the closing date of the Company’s IPO and related corporate reorganization, to December 31, 2010 by the number of weighted average shares outstanding for such period.
The following table reconciles net loss for the year ended December 31, 2010 to net loss attributable to common stockholders for the period:
The following table reflects net loss attributable to common stockholders, weighted average shares outstanding and loss per share for the year ended December 31, 2010 as previously reported and as restated:
The following is a calculation of the basic and diluted weighted average shares outstanding for the periods presented:
(1) The basic weighted average shares outstanding calculation for the year ended December 31, 2010 is based on the actual days in which the shares were outstanding for the period from June 22, 2010, the closing date of the Company’s IPO, to December 31, 2010.
(2) Because the Company reported a net loss for the year ended December 31, 2010, no unvested stock awards were included in computing loss per share for the year ended December 31, 2010 because the effect was anti-dilutive.
12. Business Segment Information
During 2012, the Company began its well services business segment, OWS, to perform completion services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the well services segment are derived from providing well completion services and related product sales. The revenues and expenses related to work performed by OWS for OPNA’s working interests are eliminated in consolidation, and only the revenues and expenses related to other working interest owners are included in the Company’s Consolidated Statement of Operations. Prior to 2012, the Company only operated its exploration and production segment. The exploration and production segment is engaged in the acquisition and development of oil and natural gas properties and includes the complementary marketing services provided by OPM. Revenues for the exploration and production segment are derived from the sale of oil and natural gas production. These segments represent the Company’s two current operating units, each offering different products and services. The Company’s corporate activities have been allocated to the supported business segments accordingly.
Management evaluates the performance of the Company’s business segments based on operating income, which is defined as segment operating revenues less operating expenses, including depreciation, depletion and amortization. Summarized financial information concerning the Company’s segments is shown in the following table:
(1) Capital expenditures reflected in the table above differ from the amounts shown in the Consolidated Statement of Cash Flows because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.
13. Significant Concentrations
Major customers. Purchasers that accounted for more than 10% of the Company’s total sales for the periods presented are as follows:
N/A Not applicable as the sales to these purchasers did not account for more than 10% of the Company’s total sales for such respective periods.
Total sales are related to the exploration and production segment, as OWS has exclusively provided well services to OPNA, and its external revenues relate to the other working interest owners in OPNA’s wells. No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2012, 2011 and 2010. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative oil and natural gas purchasers in the Company’s producing regions.
Substantially all of the Company’s accounts receivable result from sales of oil and natural gas as well as joint interest billings (“JIB”) to third-party companies who have working interest payment obligations in projects completed by the Company. No third-party company accounted for more than 10% of the Company’s total JIB receivables balance at December 31, 2012. Northern Oil & Gas Inc. and Hess Corporation accounted for approximately 16% and 14%, respectively, of the Company’s JIB receivables balance at December 31, 2011.
This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.
14. Commitments and Contingencies
Lease obligations. The Company has operating leases for office space and other property and equipment. The Company incurred rental expense of $1.5 million, $0.8 million and $0.6 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Future minimum annual rental commitments under non-cancelable leases at December 31, 2012 are as follows:
Drilling contracts. As of December 31, 2012, the Company had certain drilling rig contracts with initial terms greater than one year. In the event of early contract termination under these contracts, the Company would be obligated to pay approximately $43.7 million as of December 31, 2012 for the days remaining through the end of the primary terms of the contracts.
Volume commitment agreements. As of December 31, 2012, the Company had certain agreements with an aggregate requirement to deliver a minimum quantity of approximately 22.4 MMBbl and 14.8 Bcf from its Williston Basin project areas within a specified timeframe. Future obligations under these agreements are approximately $70.5 million as of December 31, 2012.
Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. The Company believes all such matters are without merit or involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition, results of operations or cash flows.
15. Subsequent Events
Derivative instruments. In January 2013, the Company entered into new swaps and three-way costless collar options, all of which settle monthly based on the WTI crude oil index price, for a total notional amount of 334,000 barrels in 2013, 699,000 barrels in 2014 and 62,000 in 2015. These derivative instruments do not qualify for and were not designated as hedging instruments for accounting purposes.
16. Consolidating Financial Statements
The Notes (see Note 7) are guaranteed on a senior unsecured basis by the Guarantors, which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors. Certain of the Company’s immaterial wholly owned subsidiaries do not guarantee the Notes (“Non-Guarantor Subsidiaries”).
The following financial information reflects consolidating financial information of the Company (“Issuer”) and its Guarantors on a combined basis, prepared on the equity basis of accounting. The Non-Guarantor Subsidiaries are immaterial and, therefore, not presented separately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantors.
Consolidating Balance Sheet
(In thousands, except share data)
Consolidating Balance Sheet
(In thousands, except share data)
Consolidating Statement of Operations
(In thousands)
Consolidating Statement of Operations
(In thousands)
Consolidating Statement of Operations
(In thousands)
Consolidating Statement of Cash Flows
(In thousands)
Consolidating Statement of Cash Flows
(In thousands)
Consolidating Statement of Cash Flows
(In thousands)
17. Supplemental Oil and Gas Disclosures
The supplemental data presented below reflects information for all of the Company’s oil and natural gas producing activities.
Capitalized Costs
The following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities at December 31, 2012 and 2011:
Pursuant to the FASB’s authoritative guidance on ARO, net capitalized costs include asset retirement costs of $20.7 million and $11.4 million at December 31, 2012 and 2011, respectively.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the years ended December 31, 2012, 2011 and 2010:
Results of Operations for Oil and Natural Gas Producing Activities
Results of operations for oil and natural gas producing activities, which excludes straight-line depreciation, general and administrative expenses and interest expense, are presented below.
18. Supplemental Oil and Gas Reserve Information - Unaudited
The reserve estimates at December 31, 2012, 2011 and 2010 presented in the table below are based on reports prepared by DeGolyer and MacNaughton, the Company’s independent reserve engineers, in accordance with the FASB’s authoritative guidance on oil and gas reserve estimation and disclosures. At December 31, 2012, 2011 and 2010, all of the Company’s oil and natural gas producing activities were conducted within the continental United States.
The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.
Estimated Quantities of Proved Oil and Natural Gas Reserves - Unaudited
The following table sets forth the Company’s estimated net proved, proved developed and proved undeveloped reserves at December 31, 2012, 2011 and 2010:
Purchases of Reserves in Place
In 2012, the Company purchased 966 MBoe of estimated net proved reserves from properties acquired in Burke and Mountrail counties. The Company had no significant reserve purchases in 2011. Of the total 1,479 MBoe of estimated net proved reserves purchased in 2010, 715 MBoe were from the properties acquired in Roosevelt County, Montana in November 2010 and 764 MBoe were from the properties acquired in Richland County, Montana in December 2010.
Extensions, Discoveries and Other Additions
In 2012, the Company had a total of 73,871 MBoe of additions due to extensions and discoveries. An estimated 16,548 MBoe of these extensions and discoveries were associated with new producing wells at December 31, 2012, with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 57,322 MBoe of proved undeveloped reserves were added across all three of the Company’s Williston Basin project areas associated with the Company’s 2012 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.
In 2011, the Company had a total of 43,168 MBoe of additions. An estimated 12,696 MBoe of extensions and discoveries were associated with new producing wells at December 31, 2011, with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 30,472 MBoe of proved undeveloped reserves were added across all three of the Company’s Williston Basin project areas associated with the Company’s 2011 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.
In 2010, the Company had a total of 24,473 MBoe of additions. An estimated 8,122 MBoe of extensions and discoveries were associated with new wells, which were producing at December 31, 2010, with approximately 99% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 16,351 MBoe of proved undeveloped reserves were added across all three of the Company’s Williston Basin project areas associated with the Company’s 2010 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.
Sales of Reserves in Place
In 2012, the Company did not have any sales of reserves. In November 2011, the Company sold its remaining interests in non-core oil and gas producing properties located in the Barnett shale in Texas, which had minimal impact on the Company’s estimated net proved reserves. In December 2010, the Company traded interests in three non-operated properties as part of the Richland County, Montana acquisition. These properties produce from the Red River formation and had remaining estimated net proved reserves of 123 MBoe.
Revisions of Previous Estimates
In 2012, the Company had a net negative revision of 1,983 MBoe, or 2.5% of the beginning of the year estimated net proved reserves balance. The primary causes for this revision were negative well performances offset by working interest increases in the proved locations. Actual well results in portions of the Company’s acreage came in below the proved forecasts prepared in 2011. The proved forecasts for the 2012 reserve report have been adjusted to reflect these well performances. The working interest increases arose from acreage trades, non-participation by other interest owners and additional mineral leasing in the reserve locations. Operating costs and realized prices had an immaterial impact to the reserves balance.
In 2011, the Company had a net negative revision of 288 MBoe, or 0.72% of the beginning of the year estimated net proved reserves balance. This net negative revision was the result of several immaterial changes, including well performances, net revenue interest changes, operating costs and realized prices.
In 2010, the Company had net positive revisions of 2,552 MBoe. Approximately 29% of these revisions were due to the increase in oil prices from 2009 to 2010. The unweighted arithmetic average first-day-of-the-month prices for the twelve months prior were $79.40/Bbl for the year ended December 31, 2010 as compared to $61.04/Bbl for the year ended December 31, 2009. An estimated 29% of the increase was due to higher working interests in proved wells. The remaining 42% of these revisions were due to other changes, including the estimate of recoverable hydrocarbons from proved wells.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves - Unaudited
The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.
The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $94.68/Bbl for oil and $2.75/MMBtu for natural gas for the year ended December 31, 2012, $96.23/Bbl for oil and $4.12/MMBtu for natural gas for the year ended December 31, 2011 and $79.40/Bbl for oil and $4.38/MMBtu for natural gas for the year ended December 31, 2010. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net oil and natural gas reserves at December 31, 2012, 2011 and 2010.
The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved oil and natural gas reserves for the periods presented.
19. Quarterly Financial Data - Unaudited
The Company’s results of operations by quarter for the years ended December 31, 2012 and 2011 are as follows:
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”), our principal executive officer; Chief Financial Officer (“CFO”), our principal financial officer; and Chief Accounting Officer (“CAO”), the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2012. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO, CFO and CAO as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation, our CEO, CFO and CAO have concluded that our disclosure controls and procedures were effective at December 31, 2012 at the reasonable assurance level.
Management’s report on internal control over financial reporting. Management, including our CEO, CFO and CAO, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As of December 31, 2012, management assessed the effectiveness of our internal control over financial reporting. In making this assessment, management, including our CEO, CFO and CAO, used the criteria set forth by the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2012.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this annual report on Form 10-K, has also audited the effectiveness of our internal control over financial reporting at December 31, 2012. Their “Report of Independent Registered Public Accounting Firm,” which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting at December 31, 2012, is included in Item 8.
Changes in internal control over financial reporting. During the year ended December 31, 2012, we converted to a new accounting and land software system. We took the necessary steps to monitor and maintain appropriate internal controls during this period of change. These steps included procedures to preserve the integrity of the data converted and a review by management to validate the data converted. Additionally, we provided training related to this system to individuals using the system to carry out their job responsibilities. We anticipate that the implementation of this software will strengthen the overall system of internal controls due to enhanced automation and integration of related processes. The system change was undertaken to integrate systems and consolidate information and was not undertaken in response to any actual or perceived deficiencies in our internal control over financial reporting. In conjunction with this system conversion, we also moved all of our outsourced accounting functions in-house. We completed the design and documentation of internal control processes and procedures relating to the new system and modules to supplement and complement existing internal controls over certain respective job areas. Testing of the controls related to the new system and accounting functions has been completed and was included in the scope of our assessment of our 2012 internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders.
Item 11.
Item 11. Executive Compensation
Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders.
Item 13.
Item 13. Certain Relationships and Related Transactions and Director Independence
Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders.
Item 14.
Item 14. Principal Accountant Fees and Services
Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
a. The following documents are filed as a part of this Annual Report on Form 10-K or incorporated herein by reference:
(1) Financial Statements:
See Item 8. Financial Statements and Supplementary Data.
(2) Financial Statement Schedules:
None.
(3) Exhibits:
The following documents are included as exhibits to this report:
(a) Filed herewith.
(b) Furnished herewith.
** Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on March 1, 2013.
OASIS PETROLEUM INC.
By:
/s/ Thomas B. Nusz
Thomas B. Nusz
Chairman of the Board, President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:
GLOSSARY OF OIL AND NATURAL GAS TERMS
The terms defined in this section are used throughout this Annual Report on Form 10-K:
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
“Bcf.” One billion cubic feet of natural gas.
“Boe.” Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.
“British thermal unit.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Developed reserves.” Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well.
“Development well.” A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“Economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
“Environmental assessment.” An environmental assessment, a study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of a project.
“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Formation.” A layer of rock which has distinct characteristics that differ from nearby rock.
“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
“Infill wells.” Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.
“MBbl.” One thousand barrels of crude oil, condensate or natural gas liquids.
“MBoe.” One thousand barrels of oil equivalent.
“Mcf.” One thousand cubic feet of natural gas.
“MMBbl.” One million barrels of crude oil, condensate or natural gas liquids.
“MMBoe.” One million barrels of oil equivalent.
“MMBtu.” One million British thermal units.
“MMcf.” One million cubic feet of natural gas.
“NYMEX.” The New York Mercantile Exchange.
“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
“PV-10.” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Commission.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Proved developed reserves.” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“Proved reserves.” Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“Proved undeveloped reserves.” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
“Reasonable certainty.” A high degree of confidence.
“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
“Reserves.” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Wellbore.” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“Workover.” The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.