News Column

OASIS PETROLEUM INC. - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations

February 27, 2014

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 North Dakota and Montana 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. OPNA conducts our domestic oil and natural gas exploration and production activities. We also operate a marketing business through OPM, a well services business through OWS, and a midstream services business through OMS, which are each complementary to our primary development and production activities. The businesses of OWS and OMS constitute separate reportable business segments. The revenues and expenses related to work performed by OPM, OWS and OMS 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 acquisitions and development 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, the acquisition of 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 assets 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 investors, borrowings under our revolving credit facility, cash flows provided by operating activities, proceeds from our senior unsecured notes and proceeds from our public equity offerings. Our 2013, 2012 and 2011 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 227.9 MMBoe of estimated net proved reserves with a PV-10 of $5,486.9 million and a Standardized Measure of $3,727.6 million at December 31, 2013, 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 and 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. 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 $96.96/Bbl for oil and $3.66/MMBtu for natural gas, $94.68/Bbl for oil and $2.75/MMBtu for natural gas and $96.23/Bbl for oil and $4.12/MMBtu for natural gas for the years ended December 31, 2013, 2012 and 2011, 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: commodity prices for oil and natural gas; transportation capacity; 47



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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. Additionally, we sell a significant amount of our crude oil production 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, 2013, we were flowing approximately 75% of our gross operated oil production through these gathering systems. 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 tables below. 2013 Year ended Q1 Q2 Q3



Q4 December 31, 2013 Average Realized Oil Prices ($/Bbl)(1) $ 93.33$ 91.15$ 100.75$ 85.87 $

92.34 Average Price Differential(2) 1 % 3 % 5 % 12 % 6 % 2012 Year ended Q1 Q2 Q3



Q4 December 31, 2012 Average Realized Oil Prices ($/Bbl)(1) $ 88.10$ 82.36$ 83.71$ 86.82 $

85.22 Average Price Differential(2) 14 % 12 % 9 % 2 % 9 % 2011 Year ended Q1 Q2 Q3



Q4 December 31, 2011 Average Realized Oil Prices ($/Bbl)(1) $ 82.33$ 95.48$ 83.52$ 85.46 $

86.18 Average Price Differential(2) 13 % 7 % 6 % 10 % 9 % (1) Realized oil prices do not include the effect of derivative contract settlements.



(2) Price differential reflects the difference between realized oil prices and

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 and Three Forks formations, caused the active drilling rig count in the Williston Basin to increase to approximately 192 rigs at December 31, 2013. 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, our average price differentials relative to WTI 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 and into the first quarter of 2013, average price differentials continued to narrow, primarily due to our ability to access premium coastal markets by rail. As the premium received in coastal markets contracted during the second and third quarters of 2013, our average price differentials relative to WTI increased. In the fourth quarter of 2013, our average price differentials relative to WTI continued to increase due to the pipeline market weakening as a result of refinery down time and increased United States and Canadian production. Our market optionality on the crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. 48



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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 14 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 2011 to provide well services on our operated wells, in addition to entering into fracturing service contracts with third party companies. We are also adding a second fracturing fleet to OWS in 2014 to further ensure our ability to complete our wells. 2013 Highlights We completed and placed on production 136 gross (106.1 net) operated Bakken and Three Forks wells during 2013, and increased average daily production by 51% to 33,904 Boe per day from 22,469 Boe per day in 2012. We increased estimated net proved oil and natural gas reserves at December 31, 2013 to 227.9 MMBoe, a 59% increase over year-end 2012 estimated net proved reserves. Approximately 87% of our estimated net proved reserves at year-end 2013 consisted of oil and 54% were classified as proved developed. We grew our leasehold position to 515,314 total net acres in the Williston Basin, primarily targeting the Bakken and Three Forks formations, and increased our operated drilling spacing units by 123 through acquisitions, acreage additions and trades during 2013. In addition, we increased our acreage that is held-by-production to 422,386 net acres as of December 31, 2013.



During 2013, we closed four separate purchase and sale agreements to

acquire an aggregate of approximately 161,000 net acres in the Williston Basin. In the first quarter of 2013, our salt water disposal assets were



transferred from OPNA to the newly formed OMS, which provides midstream

services to OPNA's operated wells. On September 24, 2013, we issued $1,000.0 million of 6.875% senior unsecured notes due March 15, 2022. The issuance of these notes resulted in net proceeds to us of approximately $983.6 million, which we used to fund the West Williston Acquisition.



On December 9, 2013, we completed a public offering of 7,000,000 shares

of our common stock, par value $0.01 per share, at an offering price of

$44.94 per share. Net proceeds from the offering were approximately

$314.4 million.

As of December 31, 2013, we had 14 operated rigs running.

At December 31, 2013, we had $91.9 million of cash and cash equivalents

and had total liquidity of $1,251.1 million, including our $1,500.0 revolving credit facility. Our total 2014 capital expenditure budget is $1,425 million, which includes $1,367 million for E&P capital expenditures and $58 million



for non-E&P capital expenditures. Our planned capital expenditures

primarily consist of: $1,250 million of drilling and completion (including production-related equipment) capital expenditures for operated and non-operated wells (including expected savings from services provided by OWS and OMS); $60 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;

$19 million for field facilities and other miscellaneous E&P capital expenditures;



$13 million for collection of subsurface reservoir data;

$35 million for OWS, including district tools; and

$23 million for other non-E&P capital, including items such as administrative capital and capitalized interest. Results of Operations Revenues Our oil and gas revenues are derived from the sale of oil and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Our well services and midstream revenues are primarily derived from well completion activity and salt water disposal for third-party working interest owners in OPNA's operated wells. The following table summarizes our revenues and production data for the periods presented: 49



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Table of Contents Year ended December 31, 2013 2012 2011 Operating results (in thousands): Revenues Oil $ 1,033,866$ 643,446$ 321,668 Natural gas 50,546 27,045 8,754 Well services and midstream 57,587 16,177 - Total revenues $ 1,141,999$ 686,668$ 330,422 Production data: Oil (MBbls) 11,133 7,533 3,732 Natural gas (MMcf) 7,450 4,146 1,092 Oil equivalents (MBoe) 12,375 8,224 3,914 Average daily production (Boe/d) 33,904 22,469



10,724

Average sales prices: Oil, without derivative settlements (per Bbl)(1) $ 92.34$ 85.22$ 86.18 Oil, with derivative settlements (per Bbl)(1)(2) 91.61 86.09 85.15 Natural gas (per Mcf)(3) 6.78 6.52 8.02 (1) For the years ended December 31, 2013 and 2012, average sales prices for oil are calculated using total oil revenues, excluding bulk oil sales of



$5.8 million and $1.5 million, respectively, divided by oil production.

(2) Realized prices include 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, 2013 as compared to year ended December 31, 2012 Total revenues. Our total revenues increased $455.3 million, or 66%, to $1,142.0 million during the year ended December 31, 2013 as compared to the year ended December 31, 2012. Our primary 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 11,435 Boe per day, or 51%, to 33,904 Boe per day during the year ended December 31, 2013 as compared to the year ended December 31, 2012. The increase in average daily production sold was primarily a result of a higher number of well completions during 2013 coupled with our West Williston Acquisition and East Nesson Acquisitions and offset by the decline in production in wells that were producing as of December 31, 2012. Production from wells completed in our West Williston, East Nesson and Sanish project areas contributed to average daily production during 2013 by approximately 7,119 Boe per day, 4,117 Boe per day and 706 Boe per day, respectively. Average oil sales prices, without derivative settlements, increased by $7.12/Bbl, or 8%, to an average of $92.34/Bbl for the year ended December 31, 2013 as compared to the year ended December 31, 2012. The higher production amounts sold increased revenues by $354.9 million, and higher oil and natural gas sales prices increased revenues by $54.7 million during the year ended December 31, 2013. In addition, bulk oil sales related to marketing activities included in oil revenues increased $4.3 million during the year ended December 31, 2013 as compared to the year ended December 31, 2012. Well services revenues increased $35.7 million for the year ended December 31, 2013 compared to the year ended December 31, 2012 due to an increase in well completion activity and related product sales and tool rentals. Midstream revenues totaled $5.7 million for the year ended December 31, 2013. There were no midstream revenues during 2012 because OMS did not commence activity until the first quarter of 2013. Prior to 2013, our salt water disposal systems were owned by OPNA, and the related income was included as a reduction to lease operating expenses. Well services and midstream revenues represent revenue for third-party working interest owners in OPNA's operated wells only, as work performed by OWS and OMS for OPNA's working interests are eliminated in consolidation. 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 50



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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 derivative settlements, 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 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 revenues during the year ended December 31, 2012. Expenses The following table summarizes our operating expenses for the periods indicated. Year ended December 31, 2013 2012 2011 (In thousands, except per Boe of production) Expenses: Lease operating expenses(1) $ 94,634$ 54,924$ 32,707 Well services and midstream operating expenses 30,713 11,774 - Marketing, transportation and gathering expenses 25,924 9,257 1,365 Production taxes 100,537 62,965 33,865 Depreciation, depletion and amortization 307,055 206,734 74,981 Exploration expenses 2,260 3,250 1,685 Impairment of oil and gas properties 1,168 3,581 3,610 Loss on sale of properties - - 207 General and administrative expenses 75,310 57,190 29,435 Total expenses 637,601 409,675 177,855 Operating income 504,398 276,993 152,567 Other income (expense): Net gain (loss) on derivative instruments (35,432 ) 34,164 1,595



Interest expense, net of capitalized interest (107,165 )

(70,143 ) (29,618 ) Other income (expense) 1,216 4,860 1,635 Total other income (expense) (141,381 ) (31,119 ) (26,388 ) Income before income taxes 363,017 245,874 126,179 Income tax expense 135,058 92,486 46,789 Net income $ 227,959$ 153,388$ 79,390 Costs and expenses (per Boe of production): Lease operating expenses(1) $ 7.65 $ 6.68 $ 8.36 Marketing, transportation and gathering expenses 2.09 1.13 0.34 Production taxes 8.12 7.66 8.65 Depreciation, depletion and amortization 24.81 25.14 19.16 General and administrative expenses 6.09 6.95 7.52



(1) For the year ended December 31, 2011, lease operating expenses exclude

marketing, transportation and gathering expenses to conform such amounts to

current year classifications. For the years ended December 31, 2012 and 2011, lease operating expenses include midstream income and operating expenses, which are included in well services and midstream revenues and well services and midstream operating expenses, respectively, for the year ended December 31, 2013. 51



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Year ended December 31, 2013 compared to year ended December 31, 2012 Lease operating expenses. Lease operating expenses increased $39.7 million to $94.6 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. 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 2013 well completions and acquisitions. Increased costs primarily related to workovers, chemical treatments, diesel, equipment rental and repairs, which have improved operational performance and minimized downtime in our wells. Additionally, the formation of OMS in the first quarter of 2013 resulted in income related to midstream activity being included in well services and midstream revenues, rather than as a reduction to lease operating expenses. Lease operating expenses increased from $6.68 for the year ended December 31, 2012 to $7.65 for the year ended December 31, 2013. This increase in unit operating costs was primarily due to the effect of the formation of OMS coupled with higher costs on wells we acquired in the West Williston Acquisition and the East Nesson Acquisitions. Well services and midstream operating expenses. Well services and midstream operating expenses represent third-party working interest owners' share of completion service costs and cost of goods sold incurred by OWS and midstream operating expenses incurred by OMS. The $18.9 million increase for the year ended December 31, 2013 compared to the year ended December 31, 2012 was attributable to a $17.4 million increase from OWS' well completion activity and related product sales, and a $1.5 million increase related to midstream operating expenses. There were no midstream operating expenses for the year ended December 31, 2012 because OMS did not commence activity until the first quarter of 2013. Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses includes all of our marketing, transportation and gathering charges for our oil production as well as bulk oil purchase costs. The $16.7 million increase year over year, or $0.96 increase per Boe, is primarily attributable to increased oil transportation costs associated with having additional wells connected to third-party infrastructure, combined with a $4.4 million increase in costs related to bulk oil purchases made by OPM and a $2.1 million increase due to the change in the non-cash valuation adjustments on our oil pipeline imbalances and linefill inventory. Excluding these non-cash valuation adjustments and bulk oil purchase costs, our marketing, transportation and gathering expenses on a per Boe basis would have been $1.52 and $1.04 for the years ended December 31, 2013 and 2012, respectively. Production taxes. Our production taxes for the years ended December 31, 2013 and 2012 were 9.3% and 9.4%, respectively, as a percentage of oil and natural gas sales, and are inclusive of lower incentivized production tax rates on certain new Montana wells. For each of the years ended December 31, 2013 and 2012, approximately 82% of our production was in North Dakota with an average production tax rate of approximately 11%. Depreciation, depletion and amortization (DD&A). DD&A expense increased $100.3 million to $307.1 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. The increase in DD&A expense for the year ended December 31, 2013 was primarily a result of our production increases from our wells completed during 2013. The DD&A rate for the year ended December 31, 2013 was $24.81 per Boe compared to $25.14 per Boe for the year ended December 31, 2012. The decrease in DD&A rate was a result of lower well costs for wells completed during the second half of 2012 and the first half of 2013, partially offset by costs related to the West Williston Acquisition. Our lower well costs were a result of decreases in service costs in the Williston Basin, efficiency gains, completion and well design optimization and pad development operations. The West Williston Acquisition completed on October 1, 2013 increased our DD&A rate by approximately $1.90 per Boe for the fourth quarter of 2013. Impairment of oil and gas properties. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2013 and 2012. During the years ended December 31, 2013 and 2012, we recorded non-cash impairment charges of $1.2 million and $3.6 million, respectively, for unproved properties due to leases that expired during the period and periodic assessments of unproved properties. The 2012 impairment charge included $1.8 million 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 2013, we did not record any impairment charges as a result of periodic assessments based 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. 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 $18.1 million for the year ended December 31, 2013 from $57.2 million for the year ended December 31, 2012. Of this increase, approximately $15.1 million was due to the impact of our organizational growth on employee compensation and $1.6 million was due to increased amortization of our restricted stock awards and performance share units ("PSUs") year over year. As of December 31, 2013, we had 405 full-time employees compared to 281 full-time employees as of December 31, 2012. In addition, $2.0 million was included in general and administrative expenses for costs related to our acquisitions during the year ended December 31, 2013. 52



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Derivatives. As a result of our derivative activities, we incurred an $8.1 million net cash settlement loss for the year ended December 31, 2013 and a $6.5 million net cash settlement gain for the year ended December 31, 2012. In addition, as a result of forward oil price changes, we recognized a $27.3 million non-cash mark-to-market derivative loss during the year ended December 31, 2013 and a $27.6 million non-cash mark-to-market derivative gain during the year ended December 31, 2012. Interest expense. Interest expense increased $37.0 million to $107.2 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. The increase was primarily due to the interest related to our senior unsecured notes issued in July 2012 and September 2013, both issued at an interest rate of 6.875%, coupled with interest expense incurred on borrowings under our revolving credit facility during 2013. For the year ended December 31, 2013, the weighted average debt outstanding under our revolving credit facility was $143.0 million and the weighted average interest rate incurred on the outstanding borrowings was 2.0%. There were no borrowings under our revolving credit facility during the year ended December 31, 2012. We capitalized $4.6 million and $3.3 million of interest costs for the years ended December 31, 2013 and 2012, respectively, which will be amortized over the life of the related assets. Income tax expense. Income tax expense for the years ended December 31, 2013 and 2012 was recorded at 37.2% and 37.6% 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, 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 years ended December 31, 2012 and 2011, the percentage of our total production that was in North Dakota was 82% and 85%, respectively, with an average production tax rate of approximately 11%. 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. The 2012 impairment charge included $1.8 million 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 53



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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 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 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. Liquidity and capital resources Our primary sources of liquidity as of the date of this report have been proceeds from our senior unsecured notes, borrowings under our revolving credit facility, proceeds from public equity offerings and cash flows from operations. 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, 2013, 2012 and 2011 are presented below: Year ended December 31, 2013 2012 2011 (In thousands) Net cash provided by operating activities $ 697,856$ 392,386$ 176,024 Net cash used in investing activities (2,445,076 ) (1,038,605 ) (629,390 ) Net cash provided by financing activities 1,625,674 388,794 780,718 Net change in cash $ (121,546 )$ (257,425 )$ 327,352 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. Quantitative and Qualitative Disclosures about Market Risk." Cash flows provided by operating activities Net cash provided by operating activities was $697.9 million, $392.4 million and $176.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. The increase in cash flows provided by operating activities for the year ended December 31, 2013 as compared to 2012 was primarily the result of our 50% increase in oil and natural gas production year over year. The increase in cash flows provided by operating activities for the year ended December 31, 2012 as compared to 2011 was primarily the result of an increase in oil and natural gas production of 110%. 54



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Working capital. Our working capital fluctuates primarily as a result of changes in commodity pricing and production volumes, capital spending to fund our exploratory and development initiatives and acquisitions and the impact of our outstanding derivative instruments. We had a working capital deficit of $18.8 million at December 31, 2013. We believe we have adequate liquidity to meet our working capital requirements. As of December 31, 2013, we had $1,251.1 million of liquidity available, including $91.9 million in cash and cash equivalents and $1,159.2 million available under our revolving credit facility. At December 31, 2012, we had a working capital surplus of $161.9 million. This surplus was primarily attributable to our cash and cash equivalents balance of $213.4 million at December 31, 2012 as a result of the proceeds from the issuance of our senior unsecured notes in July 2012. Cash flows used in investing activities We had cash flows used in investing activities of $2,445.1 million, $1,038.6 million and $629.4 million during the years ended December 31, 2013, 2012 and 2011, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The increase in cash used in investing activities for the year ended December 31, 2013 compared to 2012 of $1,406.5 million was a result of $1,560.1 million for acquisitions in 2013 primarily related to the West Williston Acquisition and the East Nesson Acquisitions, offset by a decrease in expenditures for the development of our properties. The increase in cash used in investing activities for the year ended December 31, 2012 compared to 2011 of $409.2 million was attributable to increased levels of expenditures for the development of our properties. Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. Our capital expenditures for drilling, development and acquisition costs for the years ended December 31, 2013, 2012 and 2011 are summarized in the following table: Year ended December 31, 2013 2012



2011

(In thousands) E&P capital expenditures by project area: West Williston $ 497,620$ 725,873$ 499,558 East Nesson 378,541 322,946 110,013 Sanish 40,568 62,879 27,436 Other(1) - - 282 Acquisitions 1,563,411 - - Total E&P capital expenditures(2) 2,480,140 1,111,698



637,289

Oasis Well Services (OWS) 15,217 15,679



-

Non-E&P capital expenditures(3) 10,941 21,196 28,685 Total capital expenditures(4) $ 2,506,298$ 1,148,573$ 665,974



(1) Other capital expenditures represent data relating to our properties in the

Barnett shale, which we sold in November 2011.

(2) Total E&P capital expenditures include $19.0 million for OMS, primarily

related to pipelines and salt water disposal wells.

(3) Non-E&P capital expenditures include such items as administrative capital

and capitalized interest.

(4) Capital expenditures (including acquisitions) reflected in the table above

differ from the amounts for capital expenditures and acquisition of oil and

gas properties shown in the statement of cash flows in our consolidated

financial statements 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. In addition, acquisitions reflected in the table include inventory purchased as part of our acquisitions, which is



included in net cash provided by operating activities in the statement of

cash flows in our consolidated financial statements.

In 2013, we spent $2,506.3 million on capital expenditures, which represented a 118% increase over the $1,148.6 million spent during 2012. Excluding the West Williston Acquisition and the East Nesson Acquisitions in 2013 totaling $1,551.7 million, we spent $954.6 million, which represented a 17% decrease compared to 2012. The reduction in capital expenditures, excluding the impact of the acquisitions, was primarily due to lower well capital costs partially offset by more drilling and completion activity. 55



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During 2013, we participated in 250 gross wells (115.1 net) that were completed and placed on production, and, as operator, we completed and placed on production 136 gross (106.1 net) of these wells. In addition, as of December 31, 2013, we had 41 gross operated wells awaiting completion and 18 gross operated wells in the process of drilling in the Bakken and Three Forks formations. Our land leasing and acquisition activity is focused in and around our existing core consolidated land positions, primarily in our West Williston project area. We anticipate investing $1,367 million for drilling, development and acquisition costs in 2014 as follows: (In thousands) Drilling and completing wells (including production-related equipment) $



1,250,000

Constructing infrastructure to support production in our core project areas



60,000

Maintaining and expanding our leasehold position



25,000

Field facilities and other E&P capital expenditures



19,000

Collection of subsurface reservoir data



13,000

Total E&P capital expenditures 1,367,000 Non-E&P capital expenditures 58,000 Total capital expenditures $ 1,425,000 While we have budgeted a total of $1,425 million for total capital expenditures in 2014, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Additionally, if we acquire additional acreage, as was the case in 2013, our capital expenditures may be higher than budgeted. We believe that cash on hand, cash flows from operating activities and availability under our revolving credit facility should be more than sufficient to fund our 2014 capital expenditure budget. However, because the operated wells funded by our 2014 drilling plan represent only a small percentage of our gross potential drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of potential drilling locations should we elect to do so. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. We actively review acquisition opportunities on an ongoing basis. Our ability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all. Cash flows provided by financing activities Net cash provided by financing activities was $1,625.7 million, $388.8 million and $780.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. For the year ended December 31, 2013, cash sourced through financing activities was primarily provided by net proceeds from the issuance of our common stock, the issuance of our senior unsecured notes and borrowings under our revolving credit facility. For the years ended December 31, 2012 and 2011, cash sourced through financing activities was primarily provided by net proceeds from the issuance of our senior unsecured notes. Sale of common stock. On December 9, 2013, we completed a public offering of 7,000,000 shares of common stock, par value $0.01 per share, at an offering price of $44.94 per share. We received net proceeds from the offering of $314.4 million, after deducting underwriting discounts and estimated offering expenses. We used a portion of these net proceeds to repay $264.4 million of outstanding indebtedness under our revolving credit facility, and the remaining proceeds were used for general corporate purposes. Senior unsecured notes. On September 24, 2013, we issued $1,000.0 million of 6.875% senior unsecured notes due March 15, 2022 (the "2022 Notes"). Interest is payable on the 2022 Notes semi-annually in arrears on each March 15 and September 15, commencing March 15, 2014. The 2022 Notes are guaranteed on a senior unsecured basis by our material subsidiaries. The issuance of these 2022 Notes resulted in net proceeds to us of approximately $983.6 million, which we used to fund a portion of the $1,478.6 million purchase price of the West Williston Acquisition (see Note 6 to our audited Consolidated Financial Statements for a description of our acquisitions). 56



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At any time prior to September 15, 2016, we may redeem up to 35% of the 2022 Notes at a redemption price of 106.875% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings as long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2022 Notes remains outstanding after such redemption. Prior to September 15, 2017, we may redeem some or all of the 2022 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after September 15, 2017, we may redeem some or all of the 2022 Notes at redemption prices (expressed as percentages of the principal amount) equal to 103.438% for the twelve-month period beginning on September 15, 2017, 101.719% for the twelve-month period beginning on September 15, 2018 and 100.00% beginning on September 15, 2019, plus accrued and unpaid interest to the redemption date. In connection with the issuance of the 2022 Notes, we, along with certain of our subsidiaries, entered into a registration rights agreement pursuant to which we agreed to file a registration statement with the SEC to allow the holders of the 2022 Notes to exchange the 2022 Notes for the same principal amount of a new issue of notes with substantially identical terms, except the new notes will be freely transferable under the Securities Act. We will use commercially reasonable efforts to cause the exchange to be completed within 360 days after the 2022 Notes issuance date. Under certain circumstances, in lieu of a registered exchange offer, we must use commercially reasonable efforts to file a shelf registration statement for the resale of the 2022 Notes. If we fail to satisfy these obligations on a timely basis, the annual interest borne by the 2022 Notes will be increased by 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective. We estimate the value of this contingent interest is immaterial at December 31, 2013. On July 2, 2012, we issued $400.0 million of 6.875% senior unsecured notes due January 15, 2023 (the "2023 Notes"). Interest is payable on the 2023 Notes semi-annually in arrears on each January 15 and July 15, commencing January 15, 2013. The 2021 Notes are guaranteed on a senior unsecured basis by our material subsidiaries. The issuance of these 2023 Notes resulted in net proceeds to us of approximately $392.4 million, which we used to fund our exploration, development and acquisition program and for general corporate purposes. At any time prior to July 15, 2015, we may redeem up to 35% of the 2023 Notes at a redemption price of 106.875% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings as long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2023 Notes remains outstanding after such redemption. Prior to July 15, 2017, we may redeem some or all of the 2023 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after July 15, 2017, we may redeem some or all of the 2023 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.438% for the twelve-month period beginning on July 15, 2017, 102.292% for the twelve-month period beginning on July 15, 2018, 101.146% for the twelve-month period beginning on July 15, 2019 and 100.00% beginning on July 15, 2020, plus accrued and unpaid interest to the redemption date. On November 10, 2011, we issued $400.0 million of 6.5% senior unsecured notes due November 1, 2021 (the "2021 Notes"). Interest is payable on the 2021 Notes semi-annually in arrears on each May 1 and November 1, commencing May 1, 2012. The 2021 Notes are guaranteed on a senior unsecured basis by our material subsidiaries. The issuance of these 2021 Notes resulted in net proceeds to us of approximately $393.4 million, which we used to fund our exploration, development and acquisition program and for general corporate purposes. At any time prior to November 1, 2014, we may redeem up to 35% of the 2021 Notes at a redemption price of 106.5% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings as long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2021 Notes remains outstanding after such redemption. Prior to November 1, 2016, we may redeem some or all of the 2021 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after November 1, 2016, we may redeem some or all of the 2021 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.25% for the twelve-month period beginning on November 1, 2016, 102.167% for the twelve-month period beginning on November 1, 2017, 101.083% for the twelve-month period beginning on November 1, 2018 and 100.00% beginning on November 1, 2019, plus accrued and unpaid interest to the redemption date. On February 2, 2011, we issued $400.0 million of 7.25% senior unsecured notes due February 1, 2019 (the "2019 Notes"). Interest is payable on the 2019 Notes semi-annually in arrears on each February 1 and August 1, commencing August 1, 2011. The 2019 Notes are guaranteed on a senior unsecured basis by our material subsidiaries. The issuance of these 2019 Notes resulted in net proceeds to us of approximately $390.0 million, which we used to fund our exploration, development and acquisition program and for general corporate purposes. 57



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Prior to February 1, 2015, we may redeem some or all of the 2019 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after February 1, 2015, we may redeem some or all of the 2019 Notes at redemption prices (expressed as percentages of the principal amount) equal to 103.625% for the twelve-month period beginning on February 1, 2015, 101.813% for the twelve-month period beginning on February 1, 2016 and 100.00% beginning on February 1, 2017, plus accrued and unpaid interest to the redemption date. The indentures governing our 2019 Notes, 2021 Notes, 2022 Notes and 2023 Notes (collectively, the "Notes") restrict our ability and the ability of certain of our 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 a number of important exceptions and qualifications. If at any time when our 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 we will cease to be subject to such covenants. Senior secured revolving line of credit. On April 5, 2013, OP LLC, as parent, and OPNA, as borrower, entered into the Second Amended Credit Facility, which has a maturity date of April 5, 2018. The Second 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 our Second Amended 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. In connection with entry into the Second Amended Credit Facility, the semi-annual redetermination of our borrowing base was also completed on April 5, 2013, which resulted in an increase to the borrowing base of the Second Amended Credit Facility from $750.0 million to $1,250.0 million. However, we elected to limit the aggregate commitment of the lenders under the Second Amended Credit Facility (the "Lenders") to $900.0 million. In addition, under the Second Amended Credit Facility, the overall credit facility increased from $1,000.0 million to $2,500.0 million. On September 3, 2013, we entered into an amendment to our Second Amended Credit Facility (the "Amendment"). In connection with the Amendment, the Lenders under our Second Amended Credit Facility completed their regular semi-annual redetermination of the borrowing base scheduled for October 1, 2013. Following the redetermination, our borrowing base increased from $1,250.0 million to $1,500.0 million and elected commitments also totaled $1,500.0 million. On a quarterly basis, we pay a 0.375% (as of December 31, 2013) 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. The Second Amended Credit Facility contains covenants that include, 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 our assets and our 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 we maintain a ratio of consolidated EBITDAX (as defined in the Second Amended Credit Facility) to consolidated Interest Expense (as defined in the Second Amended Credit Facility) 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 we maintain a Current Ratio (as defined in the Second Amended Credit Facility) of consolidated current assets (with exclusions as described in the Second Amended Credit Facility) to consolidated current liabilities (with exclusions as described in the Second Amended Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. The Second 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 Second Amended Credit Facility to be immediately due and payable. As of December 31, 2013, we had $335.6 million of borrowings and $5.2 million of outstanding letters of credit issued under the Second Amended Credit Facility, resulting in an unused borrowing base capacity of $1,159.2 million. As of December 31, 2013, the weighted average interest rate on borrowings under the Second Amended Credit Facility was 1.8%. For the year 58



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ended December 31, 2013, the weighted average debt outstanding under the Second Amended Credit Facility was $143.0 million and the weighted average interest rate incurred on the outstanding borrowings was 2.0%. As of December 31, 2012, we had no borrowings and $2.2 million of outstanding letters of credit issued under the Second Amended Credit Facility, resulting in an unused elected commitments capacity of $497.8 million. We were in compliance with the financial covenants of the Second Amended Credit Facility as of December 31, 2013 and 2012. Obligations and commitments We have the following contractual obligations and commitments as of December 31, 2013 (in thousands): Payments due by period Within 1 More than Contractual obligations Total year 1-3 years 3-5 years 5 years Operating leases(1) $ 11,111$ 2,927$ 5,949$ 2,235 $ - Drilling rig commitments(1) 26,227 24,365 1,862 - -



Volume commitment agreements(1) 49,280 10,229 21,609

17,442 - Purchase agreements(1) 4,968 994 1,987 1,987 - Cost sharing agreements(1) 12,741 5,683 7,058 - - Investment commitment(1) 7,049 - 7,049 - - Senior unsecured notes(2) 2,200,000 - - - 2,200,000 Interest payments on senior unsecured notes(2) 1,211,406 149,531 302,500 302,500 456,875 Borrowings under revolving credit facility(2) 335,570 - - 335,570 - Interest payments on borrowings under revolving credit facility(2) 1,329 1,329 - - - Asset retirement obligations(3) 36,458 540 2,037 1,009 32,872 Total contractual cash obligations $ 3,896,139$ 195,598$ 350,051$ 660,743$ 2,689,747 (1) See Note 17 to our audited consolidated financial statements for a description of our operating leases, drilling rig commitments, volume commitment agreements and investment commitment. (2) See Note 9 to our audited consolidated financial statements for a description of our senior unsecured notes, revolving credit facility and



related interest payments. As of December 31, 2013, we had $335.6 million

of borrowings and $5.2 million of outstanding letters of credit issued

under our Second Amended Credit Facility.

(3) Amounts represent our estimate of future asset retirement obligations on an

undiscounted basis. Because these costs typically extend many years into

the future, estimating these future costs requires management to make

estimates and judgments that are subject to future revisions based upon

numerous factors, including the rate of inflation, changing technology and

the political and regulatory environment. See Note 10 to our audited

consolidated financial statements.

Critical accounting policies and estimates The discussion and analysis of our financial condition and results of operations are based upon our audited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments used in preparation of our consolidated financial statements below. See Note 2 to our audited consolidated financial statements for a discussion of additional accounting policies and estimates made by management. Method of accounting for oil and natural 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 59



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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. 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. 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 we specifically identify leases that will revert to the lessor, at which time we expense the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment of oil and gas properties in our 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. 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. Oil and natural gas reserve quantities and standardized measure of future net revenue Our independent reserve engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the SEC rules allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. The SEC's rules define proved reserves as the 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. Our independent reserve engineers and technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. Revenue recognition Oil and gas revenue from our 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 our production is sold to purchasers under short-term (less than twelve month) 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 60



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reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations. As a result, we maintain 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 primarily to OPNA. Midstream revenues consist of revenues from salt water disposal for OPNA's operated wells. Prior to the formation of OMS in 2013, the salt water disposal systems were owned by OPNA, and the related income was included as a reduction to lease operating expenses. 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 our Consolidated Statement of Operations. Impairment of proved 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. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare 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, we 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 our 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. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved oil and natural gas properties will be recorded. Impairment of unproved properties The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. We have historically recognized impairment expense for unproved properties at the time when the lease term has expired or sooner based on management's periodic assessments. We consider the following factors in our assessment of the impairment of unproved properties: the remaining amount of unexpired term under our leases; our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be close to expiration; our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and our evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations by us or by other operators in areas adjacent to or near our unproved properties. Business combinations We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of oil and 61



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natural gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Capitalized interest We capitalize a portion of our interest expense incurred on our 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. Amounts capitalized are amortized over the life of the related assets. Asset retirement obligations We record 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 asset retirement obligation ("ARO") represents the estimated amount we 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 on the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in our Consolidated Statement of Operations. We determine 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. 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. Derivatives We record all derivative instruments on the Consolidated Balance Sheet as either assets or liabilities measured at their estimated fair value. 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. We have not designated any derivative instruments as hedges for accounting purposes and we do not enter into such instruments for speculative trading purposes. Cash settlements of commodity derivative instruments and gains and losses from valuation changes in the remaining unsettled commodity derivative instruments are reported under other income (expense) in our Consolidated Statement of Operations. Our 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 our Consolidated Statement of Cash Flows. Stock-based compensation Restricted stock awards. We recognize compensation expense for all restricted stock awards made to employees and directors. 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 requisite service period, which is generally the vesting period. The fair value of restricted stock grants is based on the value of our common stock on the date of grant. Assumptions regarding forfeiture rates are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized. Stock-based compensation expense recorded for restricted stock awards is included in general and administrative expenses on our Consolidated Statement of Operations. Performance share units. We recognize compensation expense for our PSUs granted to our officers. 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 62



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to this calculation could impact the valuation and thus the stock-based compensation expense recognized (see Note 12 to our audited Consolidated Financial Statements for a description of these inputs). Stock-based compensation expense recorded for PSUs is included in general and administrative expenses on our Consolidated Statement of Operations. Treasury stock Treasury stock shares represent shares withheld by us equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards. We include the withheld shares as treasury stock on our Consolidated Balance Sheet and separately pay the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of our common stock and are accounted for at cost. We do not have a publicly announced program to repurchase shares of our common stock. Income taxes Our provision for taxes includes both federal and state taxes. We record our 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. We apply significant judgment in evaluating our tax positions and estimating our 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 our estimates, which could impact our financial position, results of operations and cash flows. We also account 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 we 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. Inflation Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2013, 2012 and 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations. Off-balance sheet arrangements Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP. See "Obligations and commitments" above and Note 17 to our audited consolidated financial statements for a description of our commitments and contingencies. 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, 2013, we utilized two-way and three-way costless collar options, put spreads, swaps and swaps with sub-floors 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 63



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(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). A swap with a sub-floor is a swap coupled with a sold put (sub-floor) at which point the minimum price would be WTI crude oil index price plus the difference between the swap and the sold put strike price. 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, 2013: Weighted Average Prices Fair Value Settlement Derivative Total Notional Asset Period Instrument Amount of Oil Swap Sub-Floor Floor Ceiling (Liability) (Barrels) ($/Barrel) (In thousands) 2014 Two-way collars 1,510,000 $ 90.77$ 102.06 $ 302 2014 Three-way collars 3,530,530 $ 70.30$ 90.65$ 105.64 2,927 2014 Put spreads 11,470 $ 70.00$ 90.00 - 2014 Swaps 2,218,500 $ 95.87 (2,042 ) 2014 Swaps with subfloors 2,004,000 $ 92.60$ 70.00 (7,111 ) 2015 Two-way collars 108,500 $ 90.00$ 99.86 275 2015 Three-way collars 263,500 $ 70.59$ 90.59$ 105.25 777 2015 Swaps 108,500 $ 93.07 148 2015 Swaps with subfloors 186,000 $ 92.60$ 70.00 (6 ) $ (4,730 ) Interest rate risk. At December 31, 2013, we had $1,000.0 million of senior unsecured notes at a fixed cash interest rate of 6.875% per annum, $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. At December 31, 2013, we had $335.6 million of borrowings and $5.2 million of outstanding letters of credit issued 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 64



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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 $36,000 at December 31, 2013. 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 $3.6 million and a net derivative liability position of $8.3 million at December 31, 2013. 65



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Item 8. Financial Statements and Supplementary Data

Index to Financial Statements Report of Independent Registered Public Accounting Firm



67

Consolidated Balance Sheet at December 31, 2013 and December 31, 2012

68

Consolidated Statement of Operations for the Years Ended December 31, 2013, 2012 and 2011

69

Consolidated Statement of Changes in Stockholders' Equity for the Years Ended December 31, 2013, 2012 and 2011

70

Consolidated Statement of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011

71

Notes to the Consolidated Financial Statements 72 66



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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' 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 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, 2013, based on criteria established in Internal Control-Integrated Framework (1992) 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. 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. 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 LLPHouston, TexasFebruary 27, 2014 67



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Table of Contents Oasis Petroleum Inc. Consolidated Balance Sheet December 31, 2013 2012 (In



thousands, except share data)

ASSETS Current assets Cash and cash equivalents $ 91,901 $ 213,447 Short-term investments - 25,891 Accounts receivable - oil and gas revenues 175,653 110,341 Accounts receivable - joint interest partners 139,459 99,194 Inventory 20,652 20,707 Prepaid expenses 10,191 1,770 Advances to joint interest partners 760 1,985 Derivative instruments 2,264 19,016 Deferred income taxes 6,335 - Other current assets 391 335 Total current assets 447,606 492,686 Property, plant and equipment Oil and gas properties (successful efforts method) 4,528,958 2,348,128 Other property and equipment 188,468 49,732



Less: accumulated depreciation, depletion, amortization and impairment

(637,676 ) (391,260 ) Total property, plant and equipment, net 4,079,750 2,006,600 Assets held for sale 137,066 - Derivative instruments 1,333 4,981 Deferred costs and other assets 46,169 24,527 Total assets $ 4,711,924



$ 2,528,794

LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ 8,920 $ 12,491 Advances from joint interest partners 12,829 21,176 Revenues and production taxes payable 146,741 71,553 Accrued liabilities 241,830 189,863 Accrued interest payable 47,910 30,096 Derivative instruments 8,188 1,048 Deferred income taxes - 4,558 Total current liabilities 466,418 330,785 Long-term debt 2,535,570 1,200,000 Asset retirement obligations 35,918 22,956 Derivative instruments 139 380 Deferred income taxes 323,147 177,671 Other liabilities 2,183 1,997 Total liabilities 3,363,375 1,733,789 Commitments and contingencies (Note 17) Stockholders' equity Common stock, $0.01 par value; 300,000,000 shares authorized; 100,866,589 shares and 93,432,712 shares issued at December 31, 2013 and 2012, respectively 996 925



Treasury stock, at cost; 167,155 shares and 129,414 shares at December 31, 2013 and 2012, respectively

(5,362 ) (3,796 ) Additional paid-in-capital 985,023 657,943 Retained earnings 367,892 139,933 Total stockholders' equity 1,348,549 795,005 Total liabilities and stockholders' equity $ 4,711,924



$ 2,528,794

The accompanying notes are an integral part of these consolidated financial statements. 68



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Table of Contents Oasis Petroleum Inc. Consolidated Statement of Operations Year Ended December 31, 2013 2012 2011 (In thousands, except per share data) Revenues Oil and gas revenues $ 1,084,412$ 670,491$ 330,422 Well services and midstream revenues 57,587 16,177 - Total revenues 1,141,999 686,668 330,422 Expenses Lease operating expenses 94,634 54,924 32,707 Well services and midstream operating expenses 30,713 11,774 - Marketing, transportation and gathering expenses 25,924 9,257 1,365 Production taxes 100,537 62,965 33,865 Depreciation, depletion and amortization 307,055 206,734 74,981 Exploration expenses 2,260 3,250 1,685 Impairment of oil and gas properties 1,168 3,581 3,610 Loss on sale of properties - - 207 General and administrative expenses 75,310 57,190 29,435 Total expenses 637,601 409,675 177,855 Operating income 504,398 276,993 152,567 Other income (expense) Net gain (loss) on derivative instruments (35,432 ) 34,164 1,595 Interest expense, net of capitalized interest (107,165 ) (70,143 ) (29,618 ) Other income (expense) 1,216 4,860 1,635 Total other income (expense) (141,381 ) (31,119 ) (26,388 ) Income before income taxes 363,017 245,874 126,179 Income tax expense 135,058 92,486 46,789 Net income $ 227,959$ 153,388$ 79,390 Earnings per share: Basic (Note 14) $ 2.45 $ 1.66$ 0.86 Diluted (Note 14) 2.44 1.66 0.86 Weighted average shares outstanding: Basic (Note 14) 92,867 92,180 92,056 Diluted (Note 14) 93,411 92,513 92,241 The accompanying notes are an integral part of these consolidated financial statements. 69



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Table of Contents Oasis Petroleum Inc. Consolidated Statement of Changes in Stockholders' Equity (In thousands) Common Stock Treasury Stock Retained Total Additional Earnings Stockholders' Shares Amount Shares Amount Paid-in-Capital (Deficit) Equity Balance as of December 31, 2010 92,240 $ 920 - $ - $ 643,719$ (92,845 )$ 551,794 Stock-based compensation 243 - - - 3,656 - 3,656 Vesting of restricted shares - 1 - - (1 ) - - Treasury stock - tax withholdings (22 ) - 22 (602 ) - - (602 ) Net income - - - - - 79,390 79,390 Balance as of December 31, 2011 92,461 921 22 (602 ) 647,374 (13,455 ) 634,238 Stock-based compensation 949 - - - 10,573 - 10,573 Vesting of restricted shares - 4 - - (4 ) - - Treasury stock - tax withholdings (107 ) - 107 (3,194 ) - - (3,194 ) Net income - - - - - 153,388 153,388 Balance as of December 31, 2012 93,303 925 129 (3,796 ) 657,943 139,933 795,005 Issuance of common stock 7,000 70 - - 314,510 - 314,580 Stock-based compensation 434 - - - 12,571 - 12,571 Vesting of restricted shares - 1 - - (1 ) - - Treasury stock - tax withholdings (38 ) - 38 (1,566 ) - - (1,566 ) Net income - - - - - 227,959 227,959 Balance as of December 31, 2013 100,699 $ 996 167 $ (5,362 ) $



985,023 $ 367,892$ 1,348,549

The accompanying notes are an integral part of these consolidated financial statements. 70



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Table of Contents Oasis Petroleum Inc. Consolidated Statement of Cash Flows Year Ended December 31, 2013 2012 2011 (In thousands) Cash flows from operating activities: Net income $ 227,959$ 153,388$ 79,390 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 307,055 206,734 74,981 Impairment of oil and gas properties 1,168 3,581 3,610 Loss on sale of properties - - 207 Deferred income taxes 134,583 92,479 46,789 Derivative instruments 35,432 (34,164 ) (1,595 ) Stock-based compensation expenses 11,982 10,333 3,656 Debt discount amortization and other 4,248 2,810 1,561 Working capital and other changes: Change in accounts receivable (107,473 ) (90,103 ) (64,900 ) Change in inventory (13,941 ) (29,313 ) (2,550 ) Change in prepaid expenses (8,191 ) 346 (1,600 ) Change in other current assets (56 ) 156 (491 ) Change in other assets (3,248 ) (95 ) (139 ) Change in accounts payable and accrued liabilities 107,451 76,706 36,316 Change in other current liabilities - (472 ) 472 Change in other liabilities 887 - 317 Net cash provided by operating activities 697,856 392,386 176,024 Cash flows from investing activities: Capital expenditures (893,524 ) (1,051,365 ) (613,720 ) Acquisition of oil and gas properties (1,560,072 ) - - Derivative settlements (8,133 ) 6,545 (3,841 ) Purchases of short-term investments - (126,213 ) (184,907 ) Redemptions of short-term investments 25,000 120,316 164,913 Advances from joint interest partners (8,347 ) 12,112 5,963 Proceeds from equipment and property sales - - 2,202 Net cash used in investing activities (2,445,076 ) (1,038,605 ) (629,390 ) Cash flows from financing activities: Proceeds from issuance of senior notes 1,000,000 400,000 800,000 Proceeds from revolving credit facility 600,000 - - Principal payments on revolving credit facility (264,430 ) - - Debt issuance costs (22,910 ) (8,012 ) (18,680 ) Proceeds from sale of common stock 314,580 - - Purchases of treasury stock (1,566 ) (3,194 ) (602 ) Net cash provided by financing activities 1,625,674 388,794 780,718 Increase (decrease) in cash and cash equivalents (121,546 ) (257,425 ) 327,352 Cash and cash equivalents: Beginning of period 213,447 470,872 143,520 End of period $ 91,901$ 213,447$ 470,872 Supplemental cash flow information: Cash paid for interest, net of capitalized interest $ 85,596$ 53,488$ 13,748 Cash paid for taxes 750 107 - Supplemental non-cash transactions: Change in accrued capital expenditures $ 34,354$ 59,878$ 58,205 Change in asset retirement obligations 13,201



10,230 5,434

The accompanying notes are an integral part of these consolidated financial statements. 71



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Oasis Petroleum Inc. Notes to Consolidated Financial Statements 1. Organization and Operations of the Company OrganizationOasis Petroleum Inc. (together with its subsidiaries, "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 Delaware limited liability company on February 26, 2007. In connection with its initial public offering in June 2010 and related corporate reorganization, the Company acquired all of the outstanding membership interests in OP LLC in exchange for shares of the Company's common stock. In 2007, Oasis Petroleum North America LLC ("OPNA"), a Delaware limited liability company, was formed to conduct domestic oil and natural gas exploration and production activities. In 2011, the Company formed Oasis Well Services LLC ("OWS"), a Delaware limited liability company, to provide well services to OPNA, and Oasis Petroleum Marketing LLC ("OPM"), a Delaware limited liability company, to provide marketing services to OPNA. In 2013, the Company formed Oasis Midstream Services LLC ("OMS"), a Delaware limited liability company, to provide midstream services to OPNA. As part of the formation of OMS, the Company transferred substantially all of its salt water disposal and other midstream assets from OPNA to OMS. 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 in the Williston Basin. The Company's proved and unproved oil and natural gas properties are located in the North Dakota and Montana areas of the Williston Basin and are owned by OPNA. The Company also operates a marketing business (OPM), a well services business (OWS) and a midstream services business (OMS), all of which are complementary to its primary development and production activities. Both OWS and OMS are separate reportable business segments. 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, OWS, OMS 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. 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 72



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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, 2013 and 2012. 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: December 31, 2013 2012 (In thousands) Equipment and materials $ 11,669$ 16,438 Crude oil inventory 8,983 4,269 $ 20,652$ 20,707 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 73



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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, 2013 or 2012. 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, 2013, 2012 and 2011. 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 $1.2 million for the year ended December 31, 2013 and $3.6 million for each of the years ended ended December 31, 2012 and 2011. 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 $4.6 million, $3.3 million and $3.1 million of interest costs for the years ended December 31, 2013, 2012 and 2011, respectively. These amounts will be amortized over the life of the related assets. 74



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Other Property and Equipment Salt water disposal facilities, furniture, software, 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 30 years for salt water disposal facilities, 20 years for buildings, two to seven years for furniture, software and equipment and the remaining lease term for leasehold improvements. The calculation for the straight-line DD&A method for salt water disposal facilities takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. 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: December 31, 2013 2012 2011 (In thousands) Beginning of period $ 40,424$ 20,207$ 5,176 Exploratory well cost additions (pending determination of proved reserves) 346,814 160,813



73,947

Exploratory well cost reclassifications (successful determination of proved reserves) (264,023 ) (140,091 ) (57,646 ) Exploratory well dry hole costs (unsuccessful in adding proved reserves) - (505 ) (1,270 ) End of period $ 123,215$ 40,424$ 20,207 As of December 31, 2013, the Company had no exploratory well costs that were capitalized for a period greater than one year. Business Combinations The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, the Company reviews comparable purchases and sales of oil and natural gas properties within the same regions, and uses that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities 75



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assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Assets Held for Sale The Company occasionally markets non-core oil and gas properties. At the end of each reporting period, the Company evaluates the properties being marketed to determine whether any should be reclassified as held-for-sale. The held-for-sale criteria include: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held-for-sale in the Company's Consolidated Balance Sheet and measured at the lower of their carrying amount or estimated fair value less costs to sell. Depreciation, depletion, and amortization expense is not recorded on assets to be divested once they are classified as held for sale. 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. The amortization expense is recorded as a component of interest expense in the Company's Consolidated Statement of Operations. 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 primarily to OPNA. Midstream revenues consist of revenues from salt water disposal for OPNA's operated wells. Prior to the formation of OMS in 2013, the salt water disposal systems were owned by OPNA, and the related income was included as a reduction to lease operating expenses. 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 76



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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 interest partners for their respective portions of operating expenses and exploration and development costs. While certain of these customers and joint interest 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. In addition, a portion of the Company's 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, 2013, the Company utilized two-way and three-way costless collar options, put spreads, swaps and swaps with sub-floors 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. 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 has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Cash settlements of commodity derivative instruments and 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. 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 9 - Long-Term Debt). As of December 31, 2013, the Company had limitations 77



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under its revolving credit facility, including a provision limiting the total amount of production that may be hedged by the Company to the lesser of projected production or 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, 2013, 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. Beginning January 1, 2013, the Company assumed annual forfeiture rates by employee group ranging from 0% to 11% based on the Company's forfeiture history for this type of award as adjusted for management's expectations of forfeitures. Stock-based compensation expense recorded for restricted stock awards is included in general and administrative expenses on the Company's Consolidated Statement of Operations. 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 (see Note 12 - Stock-Based Compensation for a description of these inputs). Stock-based compensation expense recorded for PSUs is included in general and administrative expenses on the Company's Consolidated Statement of Operations. Associated Excess Tax Benefits 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 benefit related to the tax deduction received exceeds the deferred tax asset associated with the recorded stock-based compensation expense. As of December 31, 2013, the excess federal tax deduction related to stock-based compensation was $4.8 million and the excess state tax deduction related to stock-based compensation was $3.5 million. Since the Company has been in and continues to be in a net operating loss position for tax purposes, none of the excess tax deduction is 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. 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 78



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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, 2013 and 2012. 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. 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 79



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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: At fair value as of December 31, 2013 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ 742 $ - $ - $ 742 Commodity derivative instruments (see Note 4) - 3,597 - 3,597 Total assets $ 742$ 3,597 $ - $ 4,339 Liabilities: Commodity derivative instruments (see Note 4) $ - $ 8,327 $ - $ 8,327 Total liabilities $ - $ 8,327 $ - $ 8,327 At fair value as of December 31, 2012 Level 1 Level 2 Level 3 Total (In thousands) Assets: Money market funds $ 66,387 $ - $ - $ 66,387 Commodity derivative instruments (see Note 4) - 23,997 - 23,997 Total assets $ 66,387$ 23,997 $ - $ 90,384 Liabilities: Commodity derivative instruments (see Note 4) $ - $ 1,428 $ - $ 1,428 Total liabilities $ - $ 1,428 $ - $ 1,428 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, 2013 and 2012. 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 instruments presented in the tables above consist of commodity derivative instruments, which include oil collars, swaps and puts. The fair values of the Company's commodity derivative instruments 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 a moment matching method similar to Turnbull-Wakeman for Asian options. 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 value for derivative instruments 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 liability in the amount of $0.2 million at December 31, 2013 and a downward adjustment to the fair value of its net derivative asset in the amount of $29,000 at 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. The Level 3 instruments presented below consist of derivative instruments, which include oil collars, swaps and puts. 80



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Table of Contents 2013 2012 2011 (In thousands) Balance as of January 1 $ - $ (5,050 )$ (10,486 ) Total gains or (losses): Included in earnings - - 1,595 Included in other comprehensive income - - - Purchases, issuances and settlements - -



3,841

Transfers in and out of Level 3(1) - 5,050 - Balance as of December 31 $ - $ - $ (5,050 ) Change in fair value included in earnings relating to derivatives instruments still held at December 31 $ - $ - $ 5,436 (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, 2013, the Company's cash equivalents were all Level 1 assets. The carrying amount of the Company's long-term debt reported in the Consolidated Balance Sheet at December 31, 2013 is $2,535.6 million, which includes $2,200.0 million of senior unsecured notes and $335.6 million of borrowings under the Company's revolving credit facility (see Note 9 - Long-Term Debt). The fair value of the Company's senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, is $2,344.0 million at December 31, 2013. Nonfinancial Assets and Liabilities Asset retirement obligations. The carrying amount of the Company's ARO in the Consolidated Balance Sheet at December 31, 2013 is $36.5 million (see Note 10 - 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, 2013, 2012 or 2011. 4. Derivative Instruments The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2013, the Company utilized two-way and three-way costless collar options, put spreads, swaps and swaps with sub-floors 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 81



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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). A swap with a sub-floor is a swap coupled with a sold put (sub-floor) at which point the minimum price would be WTI crude oil index price plus the difference between the swap and the sold put strike price. 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 cash settlements and non-cash changes in fair value, 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, 2013, the Company had the following outstanding commodity derivative instruments, all of which settle monthly based on the WTI crude oil index price: Weighted Average Prices Fair Value Settlement Derivative Total Notional Asset Period Instrument Amount of Oil Swap Sub-Floor Floor Ceiling (Liability) (Barrels) ($/Barrel) (In thousands) 2014 Two-way collars 1,510,000 $ 90.77$ 102.06 $ 302 2014 Three-way collars 3,530,530 $ 70.30$ 90.65$ 105.64 2,927 2014 Put spreads 11,470 $ 70.00$ 90.00 - 2014 Swaps 2,218,500 $ 95.87 (2,042 ) 2014 Swaps with subfloors 2,004,000 $ 92.60$ 70.00 (7,111 ) 2015 Two-way collars 108,500 $ 90.00$ 99.86 275 2015 Three-way collars 263,500 $ 70.59$ 90.59$ 105.25 777 2015 Swaps 108,500 $ 93.07 148 2015 Swaps with subfloors 186,000 $ 92.60$ 70.00 (6 ) $ (4,730 ) The following table summarizes the location and fair value of all outstanding commodity derivative instruments recorded in the Consolidated Balance Sheet for the periods presented: Fair Value of Derivative Instrument Assets (Liabilities) Fair Value December 31, Commodity Balance Sheet Location



2013 2012

(In thousands) Crude oil Derivative instruments - current assets $ 2,264$ 19,016 Crude oil Derivative instruments - non-current assets 1,333 4,981 Crude oil Derivative instruments - current liabilities (8,188 ) (1,048 ) Crude oil Derivative instruments - non-current liabilities (139 ) (380 ) Total derivative instruments



$ (4,730 )$ 22,569

The following table summarizes the location and amounts of gains and losses from the Company's commodity derivative instruments for the periods presented:

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Table of Contents December 31, Statement of Operations Location 2013 2012 2011 (In thousands) Change in fair value of derivative instruments Net gain (loss) on derivative instruments $ (27,299 )$ 27,619$ 5,436 Derivative settlements Net gain (loss) on derivative instruments (8,133 ) 6,545 (3,841 ) Total net gain (loss) on derivative instruments $ (35,432 )$ 34,164$ 1,595 The Company has adopted the FASB's authoritative guidance on disclosures about offsetting assets and liabilities, which requires entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company's derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company's Condensed Consolidated Balance Sheet.



The following tables summarize gross and net information about the Company's commodity derivative instruments for the periods presented:

Net Amounts of Assets

Offsetting of Gross Amounts of Recognized Gross Amounts Offset in Presented in the Balance

Derivative Assets Assets the Balance Sheet Sheet (In thousands) As of December 31, 2013 $ 22,743 $ (19,146 ) $ 3,597 As of December 31, 2012 $ 68,970 $ (44,973 ) $ 23,997 Offsetting of Net Amounts of



Derivative Gross Amounts of Recognized Gross Amounts Offset in Liabilities Presented in

Liabilities Liabilities the Balance Sheet the Balance Sheet (In thousands) As of December 31, 2013 $ 27,473 $ (19,146 ) $ 8,327 As of December 31, 2012 $ 46,401 $ (44,973 ) $ 1,428 5. Property, Plant and Equipment The following table sets forth the Company's property, plant and equipment: December 31, 2013 2012 (In thousands) Proved oil and gas properties(1) $ 3,713,525



$ 2,271,711 Less: Accumulated depreciation, depletion, amortization and impairment

(612,380 ) (383,564 ) Proved oil and gas properties, net(2) 3,101,145



1,888,147

Unproved oil and gas properties 815,433



76,417

Other property and equipment 188,468



49,732

Less: Accumulated depreciation (25,296 ) (7,696 ) Other property and equipment, net(2) 163,172



42,036

Total property, plant and equipment, net $ 4,079,750



$ 2,006,600

(1) Included in the Company's proved oil and gas properties are estimates of future asset retirement costs of $32.6 million and $20.7 million at December 31, 2013 and 2012, respectively. (2) The Company reclassed substantially all of its salt water disposal and



other midstream assets from proved oil and gas properties to other property

and equipment, effective January 1, 2013. 83



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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 $1.2 million for the year ended December 31, 2013 and $3.6 million for each of the years ended December 31, 2012 and 2011. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2013, 2012, and 2011. 6. Acquisitions The following table summarizes the consideration paid for the Company's acquisitions during the year ended December 31, 2013 and the fair value of the assets acquired and liabilities assumed as of the acquisition dates. The purchase price allocations are preliminary and subject to adjustment, as the final closing statements will be completed by the second quarter of 2014. Year Ended December



31, 2013

West Williston East Nesson Consideration given to the sellers: (In thousands) Cash $ 1,496,369 $ 55,339 Forgiveness of debt - 1,896 Total consideration 1,496,369 57,235 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Proved developed properties 535,477 32,511 Proved undeveloped properties 165,907 1,807 Unproved lease acquisition costs 787,589



23,369

Other property and equipment 13,157 - Inventory 3,181 148 Total assets acquired 1,505,311 57,835 Liabilities assumed: Asset retirement obligations 6,598 307 Revenues payable 2,344 293 Total liabilities assumed 8,942 600 Total identifiable net assets $ 1,496,369 $



57,235

West Williston acquisition. On October 1, 2013, the Company completed a purchase and sale agreement (the "Purchase Agreement") with two undisclosed private sellers (the "Sellers"), pursuant to which the Company agreed to purchase approximately 136,000 net acres in its West Williston project area in the Williston Basin (the "West Williston Acquisition") for aggregate consideration of $1,496.4 million in cash (the "Purchase Price"), which is subject to further customary post close adjustments. The West Williston Acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the October 1, 2013 acquisition date. The 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). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 3 - Fair Value Measurements. The Company recorded the assets acquired and liabilities assumed in the West Williston Acquisition at their estimated fair value of $1,496.4 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. In addition, the Company 84



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included $2.0 million of costs related to the West Williston Acquisition in general and administrative expenses on its Consolidated Statement of Operations for the year ended December 31, 2013. The results of operations for the West Williston Acquisition have been included in the Company's consolidated financial statements since the October 1, 2013 closing date, including approximately$57.6 million of total revenue and $14.9 million of operating income. Summarized below are the consolidated results of operations for the years ended December 31, 2013 and 2012, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2012. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the West Williston Acquisition properties, which were derived from the historical accounting records of the Sellers. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company's expected future results of operations. Year Ended December 31, 2013 2012 (In thousands) Unaudited Revenues $ 1,297,545$ 831,575 Net income 231,217 136,004 East Nesson acquisitions. On September 26, 2013, the Company acquired certain oil and natural gas assets totaling approximately 25,000 net acres in its East Nesson project area for total consideration of $57.2 million, subject to further customary post close adjustments (the "East Nesson Acquisitions"). As part of the East Nesson Acquisitions, the Company also agreed to invest, expend and/or incur expenses of $8.2 million in connection with drilling and completion activities for certain wells (see Note 17 - Commitments and Contingencies). The results of operations for the East Nesson Acquisitions have been included in the Company's consolidated financial statements since the September 26, 2013 closing date. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the Company's Consolidated Statement of Operations. The Company did not have any significant acquisitions for the years ended December 31, 2012 and 2011. 7. Assets Held for Sale Net assets held for sale represent the assets that were or are expected to be sold, net of liabilities, which were or are expected to be assumed by the purchaser. As of December 31, 2013, the assets in the Company's Sanish project area and other non-operated leases adjacent to its Sanish position in North Dakota were held for sale (see Note 18 - Subsequent Events). The Company did not have assets classified as held for sale as of December 31, 2012. The following table presents balance sheet data related to the assets held for sale: December 31, 2013 (In thousands) Assets Oil and gas properties $ 191,384 Less: accumulated depreciation, depletion, amortization and impairment (54,318 ) Total assets $ 137,066 Liabilities Asset retirement obligation $ 1,973 Total liabilities $ 1,973 Net assets $ 135,093 85



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8. Accrued Liabilities The Company's accrued liabilities consist of the following: December 31, 2013 2012 (In thousands) Accrued capital costs $ 199,085$ 167,246 Accrued lease operating expenses 18,660 9,786 Accrued general and administrative expenses 14,203 7,703 Other accrued liabilities 9,882 5,128 Total accrued liabilities $ 241,830$ 189,863



Accrued liabilities represent the Company's estimated current payment obligations for materials and services provided by its vendors, for which invoices have not yet been received or fully processed. Invoices that have been fully processed, but not yet paid, are recorded as accounts payable.

In addition, the Company had revenue suspense of $79.7 million, production taxes payable of $22.3 million and royalties payable of $44.7 million included in revenues and production taxes payable on the Consolidated Balance Sheet for the year ended December 31, 2013. For the year ended December 31, 2012, 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. Revenue suspense represents proceeds from the sale of oil and natural gas production that have been processed by the Company on behalf of third parties, which cannot be disbursed to such third parties until certain issues are resolved, such as title issues or missing contact information. 9. Long-Term Debt Senior unsecured notes. On September 24, 2013, the Company issued $1,000.0 million of 6.875% senior unsecured notes due March 15, 2022 (the "2022 Notes"). The issuance of the 2022 Notes resulted in aggregate net proceeds to the Company of approximately $983.6 million. The Company used the proceeds from the 2022 Notes to fund the acquisition of oil and gas properties in its West Williston project area (see Note 6 - Acquisitions). In connection with the issuance of the 2022 Notes, the Company along with its material subsidiaries (the "Guarantors") entered into a registration rights agreement pursuant to which the Company and Guarantors agreed to file a registration statement with the SEC to allow the holders of the 2022 Notes to exchange the 2022 Notes for the same principal amount of a new issue of notes with substantially identical terms, except the new notes will be freely transferable under the Securities Act. The Company and the Guarantors will use commercially reasonable efforts to cause the exchange to be completed within 360 days after the 2022 Notes issuance date. Under certain circumstances, in lieu of a registered exchange offer, the Company must use commercially reasonable efforts to file a shelf registration statement for the resale of the 2022 Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the 2022 Notes will be increased by 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective. The Company estimates the value of this contingent interest is immaterial at December 31, 2013. During 2011 and 2012, the Company issued $400.0 million of 7.25% senior unsecured notes due February 1, 2019 (the "2019 Notes"), $400.0 million of 6.5% senior unsecured notes due November 1, 2021 (the "2021 Notes") and $400.0 million of 6.875% senior unsecured notes due January 15, 2023 (the "2023 Notes"), which resulted in aggregate net proceeds to the Company of approximately $1,175.8 million. The Company has used the proceeds from these notes to fund its exploration, development and acquisition program and for general corporate purposes. Interest on these notes is payable semi-annually in arrears. The 2022 Notes, the 2019 Notes, the 2021 Notes and the 2023 Notes (collectively, the "Notes") are guaranteed on a senior unsecured basis by the Company's 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; 86



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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"). Prior to certain dates, 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, 2013 and 2012. 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. On April 5, 2013, the Company, as parent, and OPNA, as borrower, entered into a second amended and restated credit agreement (the "Second Amended Credit Facility"), which has a maturity date of April 5, 2018. The Second 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 Second 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. In connection with entry into the Second Amended Credit Facility, the semi-annual redetermination of the Company's borrowing base was also completed on April 5, 2013, which increased the borrowing base of the Second Amended Credit Facility from $750.0 million to $1,250.0 million. However, the Company elected to limit the aggregate commitment of the 87



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lenders under the Second Amended Credit Facility (the "Lenders") to $900.0 million. In addition, under the Second Amended Credit Facility, the overall credit facility increased from $1.0 billion to $2.5 billion. On September 3, 2013, the Company entered into an amendment to its Second Amended Credit Facility (the "Amendment"). In connection with the Amendment, the Lenders under the Company's Second Amended Credit Facility completed their regular semi-annual redetermination of the borrowing base scheduled for October 1, 2013. Following the redetermination, the Company's borrowing base increased from $1,250.0 million to $1,500.0 million and elected commitments also totaled $1,500.0 million. Borrowings under the Second 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 Second Amended Credit Facility as an Alternate Based Rate or "ABR" loan). As of December 31, 2013, any outstanding LIBOR and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table: Applicable Margin Applicable Margin Ratio of Total Outstanding Borrowings to Borrowing Base for LIBOR Loans for ABR Loans Less than .25 to 1 1.50 % 0.00 % Greater than or equal to .25 to 1 but less than .50 to 1 1.75 % 0.25 % Greater than or equal to .50 to 1 but less than .75 to 1 2.00 % 0.50 % Greater than or equal to .75 to 1 but less than .90 to 1 2.25 % 0.75 % Greater than .90 to 1 but less than or equal 1 2.50 % 1.00 % An ABR loan may be repaid at any time before the scheduled maturity of the Second Amended Credit Facility upon the Company providing advance notification to 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 available 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. At the end of a LIBOR loan term, the Second Amended Credit Facility allows the Company to elect to repay the borrowing, continue a LIBOR loan with the same or 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, 2013) 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, 2013, the Second 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 (as defined in the Second Amended Credit Facility) to consolidated Interest Expense (as defined in the Second Amended Credit Facility) 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 Second Amended Credit Facility) of consolidated current assets (with exclusions as described in the Amended Credit Facility) to 88



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consolidated current liabilities (with exclusions as described in the Second Amended Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. The Second 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 Second Amended Credit Facility to be immediately due and payable. As of December 31, 2013, the Company had $335.6 million of borrowings and $5.2 million of outstanding letters of credit issued under the Second Amended Credit Facility, resulting in an unused borrowing base capacity of $1,159.2 million. As of December 31, 2013, the weighted average interest rate on borrowings under the Second Amended Credit Facility was 1.8%. Other than indebtedness under the Second Amended Credit Facility that becomes due in April 2018, the Company does not have any debt that matures within the five years ending December 31, 2018. The Company was in compliance with the financial covenants of the Second Amended Credit Facility as of December 31, 2013. Deferred financing costs. As of December 31, 2013, the Company had $41.8 million of deferred financing costs related to the Notes and the Second Amended Credit Facility. The deferred financing costs are included in deferred costs and other assets on the Company's Consolidated Balance Sheet at December 31, 2013 and are being amortized over the respective terms of the Notes and the Second Amended Credit Facility. Amortization of deferred financing costs recorded for the year ended December 31, 2013, 2012 and 2011 was $4.5 million, $3.0 million and $1.7 million, respectively. These costs are included in interest expense on the Company's Condensed Consolidated Statement of Operations. 10. Asset Retirement Obligations The following table reflects the changes in the Company's ARO during the years ended December 31, 2013 and 2012: Year Ended December 31, 2013(1) 2012 (In thousands) Asset retirement obligation - beginning of period $ 23,234 $



13,075

Liabilities incurred during period 11,665



7,585

Liabilities settled during period - (71 ) Accretion expense during period 1,346



872

Revisions to estimates 213



1,773

Asset retirement obligation - end of period $ 36,458 $



23,234

(1) Includes ARO for wells acquired in the West Williston Acquisition and the East Nesson Acquisitions (See Note 6 - Acquisitions). 11. Income Taxes The Company's income tax expense consists of the following: Year Ended December 31, 2013 2012 2011 (In thousands) Current: Federal $ 475 $ - $ - State - 7 - 475 7 - Deferred: Federal 122,853 82,841 42,809 State 11,730 9,638 3,980 134,583 92,479 46,789



Total income tax expense $ 135,058$ 92,486$ 46,789

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For the years ended December 31, 2013, 2012 and 2011, the Company's effective tax rate differs from the federal statutory rate of 35% primarily due to state income taxes. 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, 2013, 2012 and 2011, is set forth below: Year Ended December 31, 2013 2012 2011 (%) (In thousands) (%) (In thousands) (%) (In thousands) U.S. federal tax statutory rate 35.00 % $ 127,056 35.00 % $ 86,056 35.00 % $ 44,163 State income taxes, net of federal income tax benefit 2.06 % 7,469 2.47 % 6,068 2.38 % 3,004 Other 0.14 % 533 0.15 % 362 (0.30 )% (378 ) Annual effective tax expense 37.20 % $ 135,058 37.62 % $ 92,486 37.08 % $ 46,789



Significant components of the Company's deferred tax assets and liabilities as of December 31, 2013 and 2012, were as follows:

Year Ended December 31, 2013 2012 (In thousands)



Deferred tax assets Net operating loss carryforward $ 17,215$ 13,926 Bonus and stock-based compensation 8,060

3,571 Derivative instruments and other 1,664 - Total deferred tax assets 26,939 17,497 Deferred tax liabilities Oil and natural gas properties 343,751 191,271 Derivative instruments - 8,455 Total deferred tax liabilities 343,751 199,726



Total net deferred tax liability $ 316,812$ 182,229

The Company generated a federal net operating tax loss of $14.7 million and accrued $0.5 million of current income tax expense for the year ended December 31, 2013. The net operating loss carryforwards consist of $50.9 million of federal net operating loss carryforwards, which expire between 2030 and 2033, and $34.0 million of state net operating loss carryforwards, which expire between 2017 and 2033. 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 $17.2 million deferred tax asset related to net operating loss carryforwards is net of $1.8 million of unrealized excess tax benefits related to excess stock-based compensation on federal and state net operating losses of $4.8 million and $3.5 million, respectively. 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, 2013, 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, 2013 will expire in 2017. 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 an asset of $6.3 million at December 31, 2013 and a liability of $4.6 million at December 31, 2012. 90



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12. 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 maximum number of shares available for grant under the 2010 Long-Term Incentive Plan is 7,200,000. 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. Beginning January 1, 2013, the Company assumed annual forfeiture rates by employee group ranging from 0% to 11% based on the Company's forfeiture history for this type of award as adjusted for management's expectations of forfeitures. The following table summarizes information related to restricted stock held by the Company's employees and directors for the periods presented: Weighted Average Grant Date Shares Fair Value per Share Non-vested shares outstanding December 31, 2011 391,278 $ 25.40 Granted 753,285 29.66 Vested (396,073 ) 26.04 Forfeited (48,066 ) 31.15 Non-vested shares outstanding December 31, 2012 700,424 29.22 Granted 594,895 38.64 Vested (160,219 ) 27.66 Forfeited (144,628 ) 28.99 Non-vested shares outstanding December 31, 2013 990,472 $



28.20

Stock-based compensation expense recorded for restricted stock awards was approximately $10.2 million for each of the years ended December 31, 2013 and 2012 and $3.7 million for the year ended December 31, 2011, and is included in general and administrative expenses on the Company's Consolidated Statement of Operations. Unrecognized expense as of December 31, 2013 for all outstanding restricted stock awards was $24.8 million and will be recognized over a weighted average period of 2.0 years. The fair value of awards vested for the year ended December 31, 2013 was $6.5 million. Performance share units. The Company has granted performance share units ("PSUs") to officers of the Company under its 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. Each grant of PSUs is subject to a designated three-year initial performance period. 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 at the end of the performance period. 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 an additional year 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 for the periods presented: 91



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Table of Contents Weighted Average Grant Date Fair Value per Initial Unit Awards Unit Non-vested PSUs at December 31, 2011 - $ - Granted 155,220 26.22 Vested - - Forfeited - - Non-vested PSUs at December 31, 2012 155,220 26.22 Granted 135,620 42.01 Vested - - Forfeited (21,540 ) 32.89 Non-vested PSUs at December 31, 2013 269,300 $



33.64

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, which results in an expected percentage of PSUs to be earned during the performance period. 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 three-year 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. Beginning January 1, 2013, the Company assumed an annual forfeiture rate of 2.7% based on management's expectations of forfeitures for all PSUs granted. The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the PSUs granted: 2013 PSUs 2012 PSUs Forecast period (years) 4.00 4.01 Risk-free rate 0.65 % 0.46 % Oasis volatility 47.48 % 51.00 % Based on these assumptions, the Monte Carlo simulation model resulted in an expected percentage of PSUs earned of 112% and 98% for the 2013 and 2012 grants, respectively. Stock-based compensation expense recorded for these PSUs for the years ended December 31, 2013 and 2012 was $1.8 million and $0.4 million, respectively, and is included in general and administrative expenses on the Consolidated Statement of Operations. No stock-based compensation expense was recorded for the year ended December 31, 2011 related to the PSUs as the Company had not issued PSUs prior to July 2012. Unrecognized expense as of December 31, 2013 for all outstanding PSUs was $6.8 million and will be recognized over a remaining period of 2.9 years. For the years ended December 31, 2013, 2012 and 2011, the Company had an associated tax benefit of $4.5 million, $4.0 million and $1.4 million, respectively, related to all stock-based compensation. 13. Common Stock On December 9, 2013, the Company completed a public offering of 7,000,000 shares of its common stock, par value $0.01 per share, at an offering price of $44.94 per share. Net proceeds from the offering were approximately $314.4 million, 92



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after deducting underwriting discounts and estimated offering expenses, of which $70,000 is included in common stock and $314.3 million is included in additional paid-in-capital on the Company's Consolidated Balance Sheet as of December 31, 2013. The Company used a portion of these net proceeds to repay $264.4 million of outstanding indebtedness under its Second Amended Credit Facility, and the remaining proceeds were used to fund its exploration, development and acquisition program and for general corporate purposes. The offering was made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC on July 15, 2011. 14. Earnings Per Share Basic earnings 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 per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, unless their effect is anti-dilutive. The following is a calculation of the basic and diluted weighted average shares outstanding for the periods presented: Year Ended December 31, 2013 2012 2011 (In thousands)



Basic weighted average common shares outstanding 92,867 92,180 92,056 Dilution effect of stock awards at end of period 544 333

185

Diluted weighted average common shares outstanding 93,411 92,513 92,241 Anti-dilutive stock-based compensation awards 634 465

160

15. Business Segment Information 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 primarily derived from the sale of oil and natural gas production. In the first quarter of 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 and district tool rentals. In the first quarter of 2013, the Company formed its midstream services business segment (OMS) to perform salt water disposal and other midstream services for the Company's oil and natural gas wells operated by OPNA. Revenues for the midstream segment are primarily derived from providing salt water disposal services. Prior to 2013, the salt water disposal systems were owned by OPNA, and the related income was included as a reduction to lease operating expenses. The revenues and expenses related to work performed by OWS and OMS for OPNA's working interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated working interest owners are included in the Company's Condensed Consolidated Statement of Operations. These segments represent the Company's three 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 for the Company's three business segments is shown in the following table: 93



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Table of Contents Exploration and Midstream Production Well Services Services Consolidated (In thousands) Year Ended December 31, 2013 Revenues $ 1,084,412$ 180,686$ 29,230$ 1,294,328 Inter-segment revenues - (128,841 ) (23,488 ) (152,329 ) Total revenues 1,084,412 51,845 5,742 1,141,999 Operating income 486,697 14,305 3,396 504,398 Other income (expense) (141,397 ) 16 - (141,381 )

Income before income taxes 345,300 14,321 3,396 363,017 Total assets(1) 4,532,264 70,708 108,952 4,711,924 Capital expenditures(2) 2,472,126 15,217 18,955 2,506,298 Depreciation, depletion and amortization 304,389 2,091 575 307,055 Year Ended December 31, 2012 Revenues $ 670,491$ 82,481 $ - $ 752,972 Inter-segment revenues - (66,304 ) - (66,304 ) Total revenues 670,491 16,177 - 686,668 Operating income 276,740 253 - 276,993 Other income (expense) (31,120 ) 1 - (31,119 )

Income before income taxes 245,620 254 - 245,874 Total assets 2,475,820 52,974 - 2,528,794 Capital expenditures(2) 1,132,894 15,679 - 1,148,573 Depreciation, depletion and amortization 206,127 607 - 206,734



(1) Total assets for the exploration and production segment includes $137.1

million of assets held for sale as of December 31, 2013.

(2) 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 Consolidated Statement of Cash Flows are presented on a cash basis.

16. Significant Concentrations Major customers. For the years ended December 31, 2013 and 2012, sales to Musket Corporation accounted for approximately 11% and 10% of our total sales, respectively. 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. No other purchasers accounted for more than 10% of the Company's total sales for the years ended December 31, 2013, 2012 and 2011. Total sales include revenues from the Company's exploration and production segment only, as OWS and OMS provide services to OPNA. 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. Statoil Oil & Gas L.P. and Continental Resources Inc. accounted for approximately 15% and 10%, respectively, of the Company's JIB receivables balance at December 31, 2013. No third-party company accounted for more than 10% of the Company's total JIB receivables balance at December 31, 2012. 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. 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. 17. Commitments and Contingencies 94



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Lease obligations. The Company has operating leases for office space and other property and equipment. The Company incurred rental expense of $1.6 million, $1.5 million and $0.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. Future minimum annual rental commitments under non-cancelable leases at December 31, 2013 are as follows: (In thousands) 2014 $ 2,927 2015 2,957 2016 2,992 2017 2,235 2018 - Thereafter - $ 11,111 Drilling contracts. As of December 31, 2013, 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 $26.2 million as of December 31, 2013 for the days remaining through the end of the primary terms of the contracts. Volume commitment agreements. As of December 31, 2013, the Company had certain agreements with an aggregate requirement to deliver a minimum quantity of 11.6 MMBbl and 11.8 Bcf from its Williston Basin project areas within specified timeframes, all of which are less than six years. Future obligations under these agreements are $49.3 million as of December 31, 2013. Purchase agreements. As of December 31, 2013, the Company had certain agreements for the purchase of freshwater with an aggregate future obligation of approximately $5.0 million. Cost sharing agreements. As of December 31, 2013, the Company had certain agreements to share the cost to construct and install electrical facilities. The Company's estimated future obligation under these agreements was $12.7 million as of December 31, 2013. Investment commitment. As of December 31, 2013, the Company had a remaining capital commitment to invest, expend and/or incur expenses of $7.0 million in connection with drilling and completion activities for certain wells located in its East Nesson project area, in exchange for the transfer of assets in connection with the East Nesson Acquisitions. 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. 18. Subsequent Events Divestiture. In January 2014, the Company executed a purchase and sale agreement for the sale of certain non-operated properties in its Sanish project area and other non-operated leases adjacent to its Sanish position for approximately $333.0 million, subject to customary post-close adjustments. The sale is expected to close during the first quarter of 2014. Derivative instruments. In February 2014, the Company entered into new swap agreements for a total notional amounts of 1,100,000 barrels, 1,516,000 barrels and 62,000 barrels, which settle in 2014, 2015 and 2016, respectively, based on the WTI crude oil index price. These derivative instruments do not qualify for and were not designated as hedging instruments for accounting purposes. 95



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19. Condensed Consolidating Financial Statements The Notes (see Note 9 - Long-Term Debt) 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. Condensed Consolidating Balance Sheet (In thousands, except share data) December 31, 2013 Combined Parent/ Guarantor Intercompany Issuer Subsidiaries Eliminations Consolidated ASSETS Current assets Cash and cash equivalents $ 34,277$ 57,624 $ - $ 91,901 Accounts receivable - oil and gas revenues - 175,653 - 175,653 Accounts receivable - joint interest partners - 139,459 - 139,459 Accounts receivable - affiliates 770 9,100 (9,870 ) - Inventory - 20,652 - 20,652 Prepaid expenses 318 9,873 - 10,191 Advances to joint interest partners - 760 - 760 Derivative instruments - 2,264 - 2,264 Deferred income taxes - 6,335 - 6,335 Other current assets - 391 - 391 Total current assets 35,365 422,111 (9,870 ) 447,606 Property, plant and equipment Oil and gas properties (successful efforts method) - 4,528,958 - 4,528,958 Other property and equipment - 188,468 - 188,468 Less: accumulated depreciation, depletion, amortization and impairment - (637,676 ) - (637,676 ) Total property, plant and equipment, net - 4,079,750 - 4,079,750 Assets held for sale - 137,066 - 137,066 Investments in and advances to subsidiaries 3,450,668 - (3,450,668 ) - Derivative instruments - 1,333 - 1,333 Deferred income taxes 85,288 - (85,288 ) - Deferred costs and other assets 33,983 12,186 - 46,169 Total assets $ 3,605,304$ 4,652,446$ (3,545,826 )$ 4,711,924 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ - $ 8,920 $ - $ 8,920 Accounts payable - affiliates 9,100 770 (9,870 ) - Advances from joint interest partners - 12,829 - 12,829 96



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Revenues and production taxes payable - 146,741 - 146,741 Accrued liabilities 33 241,797 - 241,830 Accrued interest payable 47,622 288 - 47,910 Derivative instruments - 8,188 - 8,188 Total current liabilities 56,755 419,533 (9,870 ) 466,418 Long-term debt 2,200,000 335,570 - 2,535,570 Asset retirement obligations - 35,918 - 35,918 Derivative instruments - 139 - 139 Deferred income taxes - 408,435 (85,288 ) 323,147 Other liabilities - 2,183 - 2,183 Total liabilities 2,256,755 1,201,778 (95,158 ) 3,363,375 Stockholders' equity Capital contributions from affiliates - 2,930,978 (2,930,978 ) - Common stock, $0.01 par value; 300,000,000 shares authorized; 100,866,589 shares issued 996 - - 996 Treasury stock, at cost; 167,155 shares (5,362 ) - - (5,362 ) Additional paid-in-capital 985,023 8,743 (8,743 ) 985,023 Retained earnings 367,892 510,947 (510,947 ) 367,892 Total stockholders' equity 1,348,549 3,450,668 (3,450,668 ) 1,348,549 Total liabilities and stockholders' equity $ 3,605,304$ 4,652,446$ (3,545,826 )$ 4,711,924 Condensed Consolidating Balance Sheet (In thousands, except share data) December 31, 2012 Combined Parent/ Guarantor Intercompany Issuer Subsidiaries Eliminations Consolidated ASSETS Current assets Cash and cash equivalents $ 133,797$ 79,650 $ - $ 213,447 Short-term investments 25,891 - - 25,891 Accounts receivable - oil and gas revenues - 110,341 - 110,341 Accounts receivable - joint interest partners - 99,194 - 99,194 Accounts receivable - affiliates 310 5,845 (6,155 ) - Inventory - 20,707 - 20,707 Prepaid expenses 313 1,457 - 1,770 Advances to joint interest partners - 1,985 - 1,985 Derivative instruments - 19,016 - 19,016 Other current assets 235 100 - 335 Total current assets 160,546 338,295 (6,155 ) 492,686 Property, plant and equipment Oil and gas properties (successful efforts method) - 2,348,128 - 2,348,128 Other property and equipment - 49,732 - 49,732 Less: accumulated depreciation, depletion, amortization and impairment - (391,260 ) - (391,260 ) Total property, plant and equipment, net - 2,006,600 - 2,006,600 Investments in and advances to subsidiaries 1,807,010 - (1,807,010 ) - 97



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Table of Contents Derivative instruments - 4,981 - 4,981 Deferred income taxes 42,746 - (42,746 ) - Deferred costs and other assets 20,748 3,779 - 24,527 Total assets $ 2,031,050$ 2,353,655$ (1,855,911 )$ 2,528,794 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ 9 $ 12,482 $ - $ 12,491 Accounts payable - affiliates 5,845 310 (6,155 ) - Advances from joint interest partners - 21,176 - 21,176 Revenues and production taxes payable - 71,553 - 71,553 Accrued liabilities 100 189,763 - 189,863 Accrued interest payable 30,091 5 - 30,096 Derivative instruments - 1,048 - 1,048 Deferred income taxes - 4,558 - 4,558 Total current liabilities 36,045 300,895 (6,155 ) 330,785 Long-term debt 1,200,000 - - 1,200,000 Asset retirement obligations - 22,956 - 22,956 Derivative instruments - 380 - 380 Deferred income taxes - 220,417 (42,746 ) 177,671 Other liabilities - 1,997 - 1,997 Total liabilities 1,236,045 546,645 (48,901 ) 1,733,789 Stockholders' equity Capital contributions from affiliates - 1,586,780 (1,586,780 ) - Common stock, $0.01 par value; 300,000,000 shares authorized; 93,432,712 issued 925 - - 925 Treasury stock, at cost; 129,414 shares (3,796 ) - - (3,796 ) Additional paid-in-capital 657,943 8,743 (8,743 ) 657,943 Retained earnings 139,933 211,487 (211,487 ) 139,933 Total stockholders' equity 795,005 1,807,010 (1,807,010 ) 795,005 Total liabilities and stockholders' equity $ 2,031,050$ 2,353,655$ (1,855,911 )$ 2,528,794 98



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Table of Contents Condensed Consolidating Statement of Operations (In thousands) Year Ended December 31, 2013 Combined Parent/ Guarantor Intercompany Issuer Subsidiaries Eliminations Consolidated Revenues Oil and gas revenues $ - $ 1,084,412 $ - $ 1,084,412 Well services and midstream revenues - 57,587 - 57,587 Total revenues - 1,141,999 - 1,141,999 Expenses Lease operating expenses - 94,634 - 94,634 Well services and midstream operating expenses - 30,713 - 30,713 Marketing, transportation and gathering expenses - 25,924 - 25,924 Production taxes - 100,537 - 100,537 Depreciation, depletion and amortization - 307,055 - 307,055 Exploration expenses - 2,260 - 2,260 Impairment of oil and gas properties - 1,168 - 1,168 General and administrative expenses 14,044 61,266 - 75,310 Total expenses 14,044 623,557 - 637,601 Operating income (loss) (14,044 ) 518,442 - 504,398 Other income (expense) Equity in earnings of subsidiaries 299,459 - (299,459 ) - Net loss on derivative instruments - (35,432 ) - (35,432 ) Interest expense, net of capitalized interest (99,663 ) (7,502 ) - (107,165 ) Other income (expense) (335 ) 1,551 - 1,216 Total other income (expense) 199,461 (41,383 ) (299,459 ) (141,381 ) Income before income taxes 185,417 477,059 (299,459 ) 363,017 Income tax benefit (expense) 42,542 (177,600 ) - (135,058 ) Net income $ 227,959$ 299,459$ (299,459 )$ 227,959 99



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Table of Contents Condensed Consolidating Statement of Operations (In thousands) Year Ended December 31, 2012 Combined Parent/ Guarantor Intercompany Issuer Subsidiaries Eliminations Consolidated Revenues Oil and gas revenues $ - $ 670,491 $ - $ 670,491 Well services revenues - 16,177 - 16,177 Total revenues - 686,668 - 686,668 Expenses Lease operating expenses - 54,924 - 54,924 Well services operating expenses - 11,774 - 11,774 Marketing, transportation and gathering expenses - 9,257 - 9,257 Production taxes - 62,965 - 62,965 Depreciation, depletion and amortization - 206,734 - 206,734 Exploration expenses - 3,250 - 3,250 Impairment of oil and gas properties - 3,581 - 3,581 General and administrative expenses 12,591 44,599 - 57,190 Total expenses 12,591 397,084 - 409,675 Operating income (loss) (12,591 ) 289,584 - 276,993 Other income (expense) Equity in earnings of subsidiaries 202,924 - (202,924 ) - Net gain on derivative instruments - 34,164 - 34,164 Interest expense, net of capitalized interest (67,651 ) (2,492 ) - (70,143 ) Other income (expense) 1,118 3,742 - 4,860 Total other income (expense) 136,391 35,414 (202,924 ) (31,119 ) Income before income taxes 123,800 324,998 (202,924 ) 245,874 Income tax benefit (expense) 29,588 (122,074 ) - (92,486 ) Net income $ 153,388$ 202,924$ (202,924 )$ 153,388 100



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Table of Contents Condensed Consolidating Statement of Operations (In thousands) Year Ended December 31, 2011 Combined Parent/ Guarantor Intercompany Issuer Subsidiaries Eliminations Consolidated

Oil and gas revenues $ - $ 330,422 $ - $ 330,422 Expenses Lease operating expenses - 32,707 - 32,707 Marketing, transportation and gathering expenses - 1,365 - 1,365 Production taxes - 33,865 - 33,865 Depreciation, depletion and amortization - 74,981 - 74,981 Exploration expenses - 1,685 - 1,685 Impairment of oil and gas properties - 3,610 - 3,610 Loss on sale of properties - 207 - 207 General and administrative expenses 5,505 23,930 - 29,435 Total expenses 5,505 172,350 - 177,855 Operating income (loss) (5,505 ) 158,072 - 152,567 Other income (expense) Equity in earnings of subsidiaries 99,836 - (99,836 ) - Net gain on derivative instruments - 1,595 - 1,595 Interest expense, net of capitalized interest (28,310 ) (1,308 ) - (29,618 ) Other income (expense) 1,165 470 - 1,635 Total other income (expense) 72,691 757 (99,836 ) (26,388 ) Income before income taxes 67,186 158,829 (99,836 ) 126,179 Income tax benefit (expense) 12,204 (58,993 ) - (46,789 ) Net income $ 79,390$ 99,836$ (99,836 )$ 79,390 101



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Table of Contents Condensed Consolidating Statement of Cash Flows (In thousands) Year Ended December 31, 2013 Combined Parent/ Guarantor Intercompany Issuer Subsidiaries Eliminations Consolidated Cash flows from operating activities: Net income $ 227,959$ 299,459$ (299,459 )$ 227,959 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Equity in earnings of subsidiaries (299,459 ) - 299,459 - Depreciation, depletion and amortization - 307,055 - 307,055 Impairment of oil and gas properties - 1,168 - 1,168 Deferred income taxes (42,542 ) 177,125 - 134,583 Derivative instruments - 35,432 - 35,432 Stock-based compensation expenses 11,602 380 - 11,982 Debt discount amortization and other 4,018 230 - 4,248 Working capital and other changes: Change in accounts receivable (460 ) (110,266 ) 3,253 (107,473 ) Change in inventory - (13,941 ) - (13,941 ) Change in prepaid expenses (5 ) (8,186 ) - (8,191 ) Change in other current assets 235 (291 ) - (56 ) Change in other assets - (3,248 ) - (3,248 ) Change in accounts payable and accrued liabilities 20,710 89,994 (3,253 ) 107,451 Change in other liabilities - 887 - 887 Net cash provided by (used in) operating activities (77,942 ) 775,798 - 697,856 Cash flows from investing activities: Capital expenditures - (893,524 ) - (893,524 ) Acquisition of oil and gas properties - (1,560,072 ) - (1,560,072 ) Derivative settlements - (8,133 ) - (8,133 ) Redemptions of short-term investments 25,000 - - 25,000 Advances from joint interest partners - (8,347 ) - (8,347 ) Net cash provided by (used in) investing activities 25,000 (2,470,076 ) - (2,445,076 ) Cash flows from financing activities: Proceeds from issuance of senior notes 1,000,000 - - 1,000,000 Proceeds from revolving credit facility - 600,000 - 600,000 Principal payments on revolving credit facility - (264,430 ) - (264,430 ) Debt issuance costs (16,362 ) (6,548 ) - (22,910 ) Proceeds from sale of common stock 314,580 - - 314,580 Purchases of treasury stock (1,566 ) - - (1,566 ) Investment in / capital contributions from subsidiaries (1,343,230 ) 1,343,230 - - Net cash provided by (used in) financing activities (46,578 ) 1,672,252 - 1,625,674 Decrease in cash and cash equivalents (99,520 ) (22,026 ) - (121,546 ) Cash and cash equivalents at beginning of period 133,797 79,650 - 213,447 Cash and cash equivalents at end of period $ 34,277$ 57,624 $ - $ 91,901 102



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Table of Contents Condensed Consolidating Statement of Cash Flows (In thousands) Year Ended December 31, 2012 Combined Parent/ Guarantor Intercompany Issuer Subsidiaries Eliminations Consolidated Cash flows from operating activities: Net income $ 153,388$ 202,924$ (202,924 )$ 153,388 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Equity in earnings of subsidiaries (202,924 ) - 202,924 - Depreciation, depletion and amortization - 206,734 - 206,734 Impairment of oil and gas properties - 3,581 - 3,581 Deferred income taxes (29,588 ) 122,067 - 92,479 Derivative instruments - (34,164 ) - (34,164 ) Stock-based compensation expenses 10,219 114 - 10,333 Debt discount amortization and other 2,277 533 - 2,810 Working capital and other changes: Change in accounts receivable (222 ) (94,106 ) 4,225 (90,103 ) Change in inventory - (29,313 ) - (29,313 ) Change in prepaid expenses (4 ) 350 - 346 Change in other current assets (217 ) 373 - 156 Change in other assets 25 (120 ) - (95 ) Change in accounts payable and accrued liabilities 18,612 62,319 (4,225 ) 76,706 Change in other current liabilities - (472 ) - (472 ) Net cash provided by (used in) operating activities (48,434 ) 440,820 - 392,386 Cash flows from investing activities: Capital expenditures - (1,051,365 ) - (1,051,365 ) Derivative settlements - 6,545 - 6,545 Purchases of short-term investments (126,213 ) - - (126,213 ) Redemptions of short-term investments 120,316 - - 120,316 Advances from joint interest partners - 12,112 - 12,112 Net cash used in investing activities (5,897 ) (1,032,708 ) - (1,038,605 ) Cash flows from financing activities: Proceeds from issuance of senior notes 400,000 - - 400,000 Debt issuance costs (7,307 ) (705 ) - (8,012 ) Purchases of treasury stock (3,194 ) - - (3,194 ) Investment in / capital contributions from subsidiaries (644,853 ) 644,853 - - Net cash provided by (used in) financing activities (255,354 ) 644,148 - 388,794 Increase (decrease) in cash and cash equivalents (309,685 ) 52,260 - (257,425 ) Cash and cash equivalents at beginning of period 443,482 27,390 - 470,872 Cash and cash equivalents at end of period $ 133,797$ 79,650 $ - $ 213,447 103



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Table of Contents Condensed Consolidating Statement of Cash Flows (In thousands) Year Ended December 31, 2011 Combined Parent/ Guarantor Intercompany Issuer Subsidiaries Eliminations Consolidated Cash flows from operating activities: Net income $ 79,390$ 99,836$ (99,836 )$ 79,390 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Equity in earnings of subsidiaries (99,836 ) - 99,836 - Depreciation, depletion and amortization - 74,981 - 74,981 Impairment of oil and gas properties - 3,610 - 3,610 Loss on sale of properties - 207 - 207 Deferred income taxes (12,204 ) 58,993 - 46,789 Derivative instruments - (1,595 ) - (1,595 ) Stock-based compensation expenses 3,656 - - 3,656 Debt discount amortization and other 1,196 365 - 1,561 Working capital and other changes: Change in accounts receivable (88 ) (66,134 ) 1,322 (64,900 ) Change in inventory - (2,550 ) - (2,550 ) Change in prepaid expenses (73 ) (1,527 ) - (1,600 ) Change in other current assets (18 ) (473 ) - (491 ) Change in other assets (100 ) (39 ) - (139 ) Change in accounts payable and accrued liabilities 17,127 20,511 (1,322 ) 36,316 Change in other current liabilities - 472 - 472 Change in other liabilities - 317 - 317 Net cash provided by (used in) operating activities (10,950 ) 186,974 - 176,024 Cash flows from investing activities: Capital expenditures - (613,720 ) - (613,720 ) Derivative settlements - (3,841 ) - (3,841 ) Purchases of short-term investments (184,907 ) - - (184,907 ) Redemptions of short-term investments 164,913 - - 164,913 Advances from joint interest partners - 5,963 - 5,963 Proceeds from equipment and property sales - 2,202 - 2,202 Net cash used in investing activities (19,994 ) (609,396 ) - (629,390 ) Cash flows from financing activities: Proceeds from issuance of senior notes 800,000 - - 800,000 Debt issuance costs (16,838 ) (1,842 ) - (18,680 ) Purchases of treasury stock (602 ) - - (602 ) Investment in / capital contributions from subsidiaries (428,074 ) 428,074 - - Net cash provided by financing activities 354,486 426,232 - 780,718 Increase in cash and cash equivalents 323,542 3,810 - 327,352 Cash and cash equivalents at beginning of period 119,940 23,580 - 143,520 Cash and cash equivalents at end of period $ 443,482$ 27,390 $ - $ 470,872 104



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20. 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, 2013 and 2012: December 31, 2013(1) 2012 (In thousands) Proved oil and gas properties(2) $ 3,713,525



$ 2,271,711 Less: Accumulated depreciation, depletion, amortization and impairment

(612,380 ) (383,564 ) Proved oil and gas properties, net 3,101,145



1,888,147

Unproved oil and gas properties 815,433



76,417

Total oil and gas properties, net $ 3,916,578



$ 1,964,564

(1) At December 31, 2013, oil and gas properties exclude capitalized costs

related to certain assets in and around the Company's Sanish project area,

which were held for sale. (2) Included in the Company's proved oil and gas properties are estimates of future asset retirement costs of $32.6 million and $20.7 million at December 31, 2013 and 2012, 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, 2013, 2012 and 2011: Year Ended December 31, 2013 2012 2011 (In thousands) Acquisition costs: Proved oil and gas properties $ 752,454$ 3,159$ 3,356 Unproved oil and gas properties 837,419 34,098 15,197 Exploration costs 2,260 3,250 1,685 Development costs 890,267 1,074,441 618,737 Asset retirement costs 11,856 9,359 5,055 Total costs incurred $ 2,494,256$ 1,124,307$ 644,030



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.

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Table of Contents Year Ended December 31, 2013 2012 2011 (In thousands) Revenues $ 1,084,412$ 670,491$ 330,422 Production costs 221,095 127,146 67,937 Depreciation, depletion and amortization 298,999 202,398



74,101

Exploration costs 2,260 3,250



1,685

Impairment of oil and gas properties 1,168 3,581 3,610 Loss on sale of properties - - 207 Income tax expense 196,312 116,941 64,009 Results of operations for oil and natural gas producing activities $ 364,578$ 217,175$ 118,873 106



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21. Supplemental Oil and Gas Reserve Information - Unaudited The reserve estimates at December 31, 2013, 2012 and 2011 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, 2013, 2012 and 2011, 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, 2013, 2012 and 2011: 107



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Table of Contents Oil Gas (MBbl) (MMcf) MBoe 2011 Proved reserves Beginning balance 36,550 19,379 39,780 Revisions of previous estimates (262 ) (159 ) (288 ) Extensions, discoveries and other additions 36,464 40,220 43,168 Sales of reserves in place (56 ) (518 ) (142 ) Purchases of reserves in place 100 65



111

Production (3,732 ) (1,087 ) (3,914 ) Net proved reserves at December 31, 2011 69,064 57,900 78,715 Proved developed reserves, December 31, 2011 31,749 24,535 35,839 Proved undeveloped reserves, December 31, 2011 37,315 33,365 42,876 2012 Proved reserves Beginning balance 69,064 57,900 78,715 Revisions of previous estimates (567 ) (8,495 ) (1,983 ) Extensions, discoveries and other additions 66,245 45,759 73,871 Sales of reserves in place - -



-

Purchases of reserves in place 881 512



966

Production (7,533 ) (4,146 ) (8,224 ) Net proved reserves at December 31, 2012 128,090 91,530 143,345 Proved developed reserves, December 31, 2012 62,602 44,695 70,051 Proved undeveloped reserves, December 31, 2012 65,488 46,835 73,294 2013 Proved reserves Beginning balance 128,090 91,530 143,345 Revisions of previous estimates 3,390 10,411



5,125

Extensions, discoveries and other additions 40,784 31,856 46,094 Sales of reserves in place

- -



-

Purchases of reserves in place 37,459 49,631



45,731

Production (11,133 ) (7,450 ) (12,375 ) Net proved reserves at December 31, 2013 198,590 175,979 227,920 Proved developed reserves, December 31, 2013 106,774 92,170 122,136 Proved undeveloped reserves, December 31, 2013 91,816 83,809 105,784 Purchases of Reserves in Place In 2013, the Company purchased 45,731 MBoe of estimated net proved reserves from properties acquired in the West Williston Acquisition and the East Nesson Acquisitions. 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. Extensions, Discoveries and Other Additions In 2013, the Company had a total of 46,094 MBoe of additions due to extensions and discoveries. An estimated 22,190 MBoe of these extensions and discoveries were associated with new producing wells at December 31, 2013, with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 23,904 MBoe of proved undeveloped reserves were added across all three of the Company's Williston Basin project areas associated with the Company's 2013 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations. 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 57,323 MBoe of proved 108



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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. Sales of Reserves in Place In 2013 and 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 a minimal impact on the Company's estimated net proved reserves. Revisions of Previous Estimates In 2013, the Company had a net positive revision of 5,125 MBoe, or 3.6% of the beginning of the year estimated net proved reserves balance. This net positive revision was the result of several immaterial changes, including well performances, working interests, operating costs and realized prices. 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 0.7% 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. 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 $96.96/Bbl for oil and $3.66/MMBtu for natural gas for the year ended December 31, 2013, $94.68/Bbl for oil and $2.75/MMBtu for natural gas for the year ended December 31, 2012 and $96.23/Bbl for oil and $4.12/MMBtu for natural gas for the year ended December 31, 2011. 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 proved reserves at December 31, 2013, 2012 and 2011. 109



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Table of Contents At December 31, 2013 2012 2011 (In thousands) Future cash inflows $ 19,063,500$ 11,321,992$ 6,508,604 Future production costs (5,473,767 ) (2,809,960 ) (1,690,264 ) Future development costs (1,904,095 ) (1,434,648 ) (783,486 ) Future income tax expense (3,628,977 ) (2,123,973 ) (1,225,395 ) Future net cash flows 8,056,661 4,953,411 2,809,459 10% annual discount for estimated timing of cash flows (4,329,102 ) (2,693,514 ) (1,489,988 ) Standardized measure of discounted future net cash flows $ 3,727,559 $



2,259,897 $ 1,319,471

The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented. 2013 2012 2011 (In thousands) January 1, $ 2,259,897$ 1,319,471$ 485,735 Net changes in prices and production costs 254,979 (7,814 ) 299,108 Net changes in future development costs 57,566 28,124 (38,244 ) Sales of oil and natural gas, net (857,540 ) (542,515 ) (262,485 ) Extensions 1,111,202 1,358,479 989,697 Discoveries - - - Purchases of reserves in place 858,382 15,890



2,679

Sales of reserves in place - - (2,499 ) Revisions of previous quantity estimates 99,954 (47,957 ) (5,058 ) Previously estimated development costs incurred 373,912 480,925 146,847 Accretion of discount 346,068 190,370 69,782 Net change in income taxes (774,910 ) (400,196 ) (372,146 ) Changes in timing and other (1,951 ) (134,880 ) 6,055 December 31, $ 3,727,559$ 2,259,897$ 1,319,471 110



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22. Quarterly Financial Data - Unaudited The Company's results of operations by quarter for the years ended December 31, 2013 and 2012 are as follows: For the Year Ended December 31, 2013 First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands) Revenues $ 248,304$ 254,582$ 305,498$ 333,615 Operating income 117,953 113,450 150,862 122,133 Net income 51,851 67,119 54,499 54,490 For the Year Ended December 31, 2012 First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands) Revenues $ 138,566$ 149,063$ 184,710$ 214,327 Operating income 58,152 60,184 72,038 86,619 Net income 16,442 76,041 18,314 42,591


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