Notes to Consolidated Financial Statements

Note 1 – SIGNIFICANT ACCOUNTING POLICIES

General. RKI Exploration & Production, LLC (“RKI” or the “Company”) is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas. Our proved oil and natural gas reserves are located in New Mexico, Oklahoma, Texas and Wyoming. RKI was organized as a limited liability company under the laws of the State of Delaware in November 2005, and was funded through private equity contributions from various individuals, including its President and CEO, Ronnie K. Irani. The provisions of the underlying limited liability company agreement stipulate that RKI shall have perpetual existence unless and until it is dissolved in accordance with the provisions of the agreement. No member shall be bound by, or personally liable for, the Company’s expenses, liabilities or obligations.

Our growth in oil and natural gas assets has primarily been funded through the sale of shares to various individuals and private equity investors, borrowings under bank credit facilities, issuance of Senior Notes, and internally generated operating cash flows. See Note 4 - Long-term Debt and Note 8 - Members’ Equity.

Basis of Presentation. Our accounting policies reflect industry practices and conform to accounting principles generally accepted in the United States of America (“US GAAP”). The accompanying consolidated financial statements include the accounts of RKI and its wholly-owned subsidiaries. All material intercompany accounts and transactions have been eliminated for all periods presented. In our capacity as operator of oil and natural gas properties which have other owners in addition to RKI, we receive and distribute third party revenues and withhold from third party revenues the associated gross production taxes payable to the respective tax jurisdiction. All revenue and production tax amounts in the accompanying consolidated statements of income are presented net to our ownership in the respective property. Certain reclassifications have been made to the prior period balance sheet and statement of cash flows presented herein to conform to the current year presentation. Such reclassifications were immaterial.

Use of Estimates. The preparation of the consolidated financial statements in conformity with US GAAP requires us to make estimates and assumptions that affect the reported amounts for assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities in the consolidated financial statements and accompanying notes. The most significant estimates relate to the accrual of oil and natural gas sales, estimates of proved oil and natural gas reserves which are used in the calculation of depletion expense and impairment charges, estimates of future plugging and abandonment costs, and valuation estimates for derivative commodity contracts. Actual results could differ from the estimates we use in the preparation of the consolidated financial statements. To the extent assumptions and estimates change in the future, the effect on our results of operations could be significant to any reporting period.

Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments generally with original maturities of three months or less. The cash balances at December 31, 2014 and 2013 include $649,000 which is pledged as collateral pursuant to the bonding requirements of certain governmental agencies.

Accounts Receivable and Concentration of Credit Risk. We sell oil and natural gas to various customers, participate with other parties in the drilling, completion and operation of oil and natural gas wells, and enter into fixed-price commodity contracts, some of which are long-term. The balances of accounts receivable for each period presented are primarily comprised of amounts due from purchasers for oil and natural gas produced and sold and from other owners in our operated oil and natural gas properties for drilling and completion costs. As of December 31, 2014, OOGC America, Inc. and Chesapeake Energy Corporation (“Chesapeake”) owed us $16.9 million and $9.2 million, respectively, for drilling and completion costs in wells we operate. Full payment is anticipated. As of December 31, 2013, Chesapeake owed us $50.1 million for the sale of oil and natural gas production and for their share of drilling and completion costs. All such amounts were collected in 2014. See Note 3 – Property Acquisitions and Divestitures. Excluding the aforementioned receivables, the majority of accounts receivable at December 31, 2014 and 2013 represents amounts due from purchasers of our oil and natural gas production which generally are very large enterprises with established investment grade credit ratings. We do not require the posting of collateral from our purchasers. The balance of allowance for bad debts provided as of December 31, 2014 and 2013 was immaterial. We use the specific identification method when providing for bad debts, based on an evaluation of individual receivable collectability. The determination of whether a receivable is past due is based on payment performance.

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Notes to Consolidated Financial Statements (continued)

At December 31, 2014, we had approximately $41.8 million of cash on deposit in financial institutions. Of this balance, $1.6 million was fully covered by FDIC insurance. However, we believe the credit risk is minimal due to the credit quality of the respective financial institutions.

Inventory. At December 31, 2014 and 2013, inventory consisted of tubular goods which we plan to use in drilling and production activities during the following twelve months totaling approximately $11.1 million and $5.0 million, respectively, and crude oil produced and stored in lease tanks prior to delivery to the purchaser in the amount of $3.0 million and $2.0 million, respectively. Inventory is presented as a current asset in the accompanying balance sheets, shown at the lower of cost or market using the weighted average cost method for tubular goods, and the cost to develop and produce for crude oil inventory.

Property and Equipment. We utilize the successful efforts method of accounting for oil and natural gas property activity. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, these costs are charged to expense. Other exploration costs, including delay rentals and seismic costs, are charged to expense as incurred. For the years ended December 31, 2014, 2013 and 2012, exploration costs totaled approximately $19.5 million, $16.9 million and $19.6 million, respectively. The largest components of total expensed exploration costs for 2014 included $16.2 million of expired leasehold costs, $1.7 million of delay rentals, and $1.3 million of seismic costs; the largest components of total expensed exploration costs for 2013 included $5.5 million of seismic costs and $9.8 million of expired leasehold costs; and the largest components of total expensed exploration costs for 2012 included $3.4 million associated with unsuccessful exploratory wells, $9.5 million of seismic costs, and $5.7 million of expired leasehold costs. Development costs, which include the costs of drilling and equipping development wells, whether successful or unsuccessful, are capitalized as incurred. All general and administrative costs are expensed as incurred. Depreciation, depletion and amortization of capitalized costs of proved oil and natural gas properties is computed by the unit-of-production method on a field-by-field basis based on estimated proved reserves. Estimated proved reserves information is derived from reserve engineering studies prepared by independent engineering firms in accordance with regulations prescribed by the Securities and Exchange Commission (“SEC”). The costs of unproved oil and natural gas properties are assessed quarterly on a property-by-property basis. If unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. If unproved properties are determined not to be productive, or if the value has been otherwise impaired, the excess carrying value is charged to expense.

We utilize the pooling of assets concept when recording property conveyances and related transactions made in connection with joint undertakings intended to find, develop, or produce oil or natural gas from a property or group of properties. As such, gains or losses may not be recognized at the time of the conveyance of properties or when cash proceeds are received or paid pursuant to the terms of the underlying joint development agreement.

Upon the sale of an entire interest in a proved property that constitutes a separate amortization base, we recognize a gain or loss equal to the difference between the amount of sales proceeds and the unamortized cost of the property. No gain or loss is recognized upon the sale of a partial interest in a proved property unless non-recognition significantly affects the unit-of-production amortization rate. Sales proceeds associated with the partial sale of an unproved property are credited against the carrying value of the unproved property, treated as a recovery of cost. If sales proceeds exceed the carrying value of the unproved property, a gain or loss is recognized.

Interest is capitalized on exploration and development activities that are in the process of development. No interest is capitalized on unproved leasehold costs that are not in the process of evaluation.

The carrying value of our oil and natural gas properties is reviewed on a field-by-field basis for indications of impairment whenever events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether an impairment has occurred, we estimate the expected undiscounted future net cash flows from our oil and natural gas properties as of the date of determination, and compare them to the respective carrying value amounts. These estimated future cash flows are based on proved and risk-adjusted probable reserves and forward market prices for oil and natural gas that existed as of the date of determination. Those oil and natural gas properties which have carrying amounts in excess of estimated future cash flows are deemed impaired. The carrying value of impaired properties is adjusted to an estimated fair value by discounting the estimated expected future cash flows attributable to the properties at a discount rate estimated to be representative of the market for such properties. The excess is charged to expense and may not be reinstated.

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Notes to Consolidated Financial Statements (continued)

For the year ended December 31, 2014, an impairment charge of $217,000 was recognized for the Roswell field in Chaves County, New Mexico. The impairment charge was primarily attributable to a decline in oil prices in the fourth quarter of 2014. For the year ended December 31, 2013, we recorded an impairment charge of $4.9 million, the vast majority of which related to the Prohibition field in Lea County, New Mexico, which is operated by third parties. The impairment was the result of limited reserve additions from drilling activity occurring in this field during 2013, which was quantified in the preparation of our year-end reserve report. For the year ended December 31, 2012, an impairment charge of $1.1 million was recognized for the Anthon field located in western Oklahoma. The impairment charge resulted primarily from a decline in natural gas prices. Lower oil and natural gas prices or downward revisions of reserve estimates could result in future impairment recognition.

We provide for the estimated costs, at current prices, of dismantling, plugging and removing oil and natural gas wells and production facilities. These estimated costs are capitalized as part of the carrying amount of our oil and natural gas properties, recorded at discounted values based on the estimated productive lives of the associated oil and natural gas properties and amortized by the unit-of-production method. The salvage value of well equipment and production facilities recoverable at the date of disposition is ignored in the calculation of the liability. The retirement liability is accreted over the life of the underlying property until the liability is settled or the well is sold. See Note 14 – Asset Retirement Obligations. The initial establishment of this liability, future accretion, and changes in cost estimates all represent noncash transactions and, therefore, are not reflected in the accompanying consolidated statements of cash flows.

Other property and equipment, including natural gas gathering systems, is carried at cost in the accompanying consolidated balance sheets. Depreciation of other property and equipment is provided by using the straight-line method over estimated useful lives of three to 20 years. We evaluate the carrying value of other property and equipment used in operations for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on estimated undiscounted future cash flows attributable to the assets as compared to their carrying value. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than fair value.

Revenue Recognition. Oil, natural gas and natural gas liquids (“NGL”) revenues are recognized when sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchaser’s pipeline or truck. As a result of the complexity of the requirements necessary to gather information from numerous purchasers and measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil, natural gas and NGL production may take 60 days or more following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production which are included in our financial results for the related period. We record any differences, which are not expected to be significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.

Natural Gas Sales and Imbalances. We use the sales method of accounting for natural gas imbalances in those circumstances where we have underproduced or overproduced our ownership percentage in a natural gas well. Under this method, a receivable or a liability is recorded to the extent that an underproduced or overproduced position in a reservoir cannot be recouped through the production of remaining reserves. Natural gas imbalance liabilities are immaterial for each period presented herein.

Income Taxes. RKI is a limited liability company treated as a corporation for federal and state income tax purposes, and we conduct operations in three states which assess taxes on income, Oklahoma, New Mexico and Texas. We provide for current and deferred federal and state income taxes in our results of operations, and recognize deferred income tax assets and liabilities on all significant temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases.

We recognize tax positions in our income tax provision when a determination is made that the relevant tax authority would more likely than not sustain a position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest amount that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant taxing authority. We have evaluated

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Notes to Consolidated Financial Statements (continued)

our tax positions for the years ended December 31, 2014, 2013 and 2012 and concluded that no uncertain tax positions that require recognition in the consolidated financial statements had been taken. Our tax returns filed for 2011 through 2013 are open for federal examination. Our policy is to include any assessed interest and penalty expense within income tax expense in the consolidated statements of income.

Price Risk Management. From time to time we reduce our exposure to unfavorable changes in oil and natural gas prices by utilizing fixed-price commodity swap and option contracts (“fixed-price contracts”). These fixed-price contracts are recognized as assets or liabilities in the accompanying consolidated balance sheets, measured at fair value. Accounting for the changes in fair value for these contracts depends on the intended use and the resulting designation. Designation is established at the inception of a contract, but redesignation is permitted. For fixed-price contracts designated as cash flow hedges which meet specified effectiveness criteria, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in the fair value of fixed-price contracts which are not designated as cash flow hedges or do not meet specified effectiveness guidelines are recorded in earnings as the changes occur. None of the fixed-price contracts in effect during the three years ended December 31, 2014 were designated as hedges for accounting purposes; consequently, all changes in the fair value of these contracts have been recorded in earnings in the respective period through December 31, 2014. Cash settlements received under fixed-price contracts are reflected as operating activities in the accompanying consolidated statements of cash flows. See Note 11 – Derivatives.

Loan Origination Costs. Other long-term assets as of December 31, 2014 and 2013 includes costs incurred in connection with the issuance and subsequent increases in our revolving bank credit facility, and the issuance of our 8.5% Senior Notes due 2021. In July 2013, we retired our second lien term loan facility, which was entered into in July 2012, with a portion of the proceeds from the issuance of our 8.5% Senior Notes due 2021. Unamortized loan origination costs associated with the second lien term loan facility of approximately $3.3 million were charged to expense, reflected as a loss on early extinguishment of debt in the statement of income for the year ended December 31, 2013. Costs associated with the issuance of the 8.5% Senior Notes due 2021 were capitalized. Unamortized issuance costs at December 31, 2014 and 2013 totaled approximately $10.9 million and $10.1 million, respectively, and are being amortized over the remaining lives of the respective credit facility. See Note 4 – Long-term Debt.

Goodwill. We recognize goodwill in the acquisition of a business when the aggregate fair value of net tangible and identifiable intangible assets is less than the total consideration paid. Goodwill is tested for impairment annually each October, or more frequently based upon changes in external factors. The impairment test compares the carrying value of goodwill to its estimated fair value; if the carrying value exceeds the fair value, the excess carrying value is charged to operations. No impairment of goodwill has been identified for the years ended December 31, 2014, 2013 and 2012.

Recently Issued Accounting Standards. In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606). The standard generally requires an entity to identify performance obligations in its contracts with customers, estimate the amount of variable consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The Standard is effective for RKI for annual and interim periods beginning after December 15, 2017, and permits the use of either the retrospective or cumulative effect transition method. We are evaluating the impact of the provisions of ASU 2014-09; however, the standard is not expected to have a material effect on our consolidated financial statements and related disclosures.

Subsequent Events . We have evaluated subsequent events through March 12, 2015, the date the financial statements were available to be issued. See Note 16 – Subsequent Events for a discussion of subsequent event matters.

Note 2 – PROPERTY AND EQUIPMENT

Capitalized Costs. Our oil and natural gas acquisition, exploration and development activities are conducted in the United States in Oklahoma, New Mexico, Texas and Wyoming. The following table summarizes the capitalized costs associated with these activities as of December 31, 2014 and 2013.

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Depreciation, depletion and amortization expense of oil and natural gas properties (“DD&A”) for the years ended December 31, 2014, 2013 and 2012 was $204.9 million, $138.5 million and $61.5 million, respectively. DD&A per barrel of oil equivalent (“Boe”) for the years ended December 31, 2014, 2013 and 2012, was $21.23, $21.96 and $21.78, respectively. Interest of approximately $3.9 million, $3.5 million and $2.4 million was capitalized in connection with our acquisition, exploration and development activities in 2014, 2013 and 2012, respectively. Depreciation of other property and equipment was approximately $6.9 million, $3.5 million and $2.1 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Unproved oil and natural gas properties at December 31, 2014 consisted of acreage positions which will be evaluated over their respective lease terms or as drilling results are determined. Certain of these acreage positions are expected to be drilled in 2015. The carrying value of these positions may be reclassified as proved oil and natural gas properties or charged to expense, depending on the nature and results of the associated drilling. The terms of certain of our unproved leases require periodic drilling operations to be conducted after the initial lease term has expired (generally three to five years) in order to preserve mineral rights to the undrilled spacing units.

RKI invests in gathering systems and processing facilities to complement our natural gas operations in regions where we have significant production and additional infrastructure is required. By doing so, we are better able to manage the value received for and the costs of gathering, treating and processing natural gas. These systems are designed primarily to gather our production for delivery into major intrastate or interstate pipelines. Our natural gas gathering systems are located in New Mexico, Texas and Wyoming and consist of approximately 290 miles of gathering pipelines. We currently generate revenue from our gathering, treating and compression activities through fixed-rate fee structures, and have also utilized cost of service fee structures in the past. Prior to July 19, 2013, we owned a 50% non-operated position in a natural gas gathering system operated by Access Midstream Partners, L.P., located in Converse County, Wyoming. We sold this ownership position in July 2013 for total proceeds of $107.5 million. Subsequent to this transaction, substantially all gathering fee income generated by our gathering systems has been attributable to the gathering and transportation of our own produced natural gas. Accordingly, this income is eliminated upon the preparation of our consolidated financial statements. The gathering systems we participate in are located in developing areas and require significant build-out capital expenditures. The majority of the associated capital expenditures are funded through availability under bank credit facilities and equity commitments, and through cash flows from operating activities.

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For the years ended December 31, 2014, 2013 and 2012, we incurred costs associated with the drilling of exploratory wells of $22.1 million, $15.5 million and $29.5 million, respectively. Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling operations are complete, we determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where we estimate that economically producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of income as a component of “Exploration costs”. If the determination of proved reserves for an exploratory well is pending the completion or testing of such well at the end of the reporting period, the associated drilling costs are classified in the consolidated balance sheets as “Unproved oil and natural gas properties” until the determination is made in a subsequent period.

On a quarterly basis, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities, in particular, whether we are making sufficient progress in our ongoing exploration and appraisal efforts. If we determine that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in the period of determination.

The following table presents the amount of capitalized exploratory drilling costs pending evaluation at December 31, 2014, 2013 and 2012, and the changes in those amounts during the years then ended:

Note 3 – PROPERTY ACQUISITIONS AND DIVESTITURES

Powder River Basin Property Exchange. In May 2007, we entered into a Joint Development Agreement (“JDA”) with Chesapeake Energy Corporation (“Chesapeake”) to pursue an exploration and development play in the Powder River Basin of Wyoming. The agreement extended a 50% ownership in the project to Chesapeake in exchange for

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Notes to Consolidated Financial Statements (continued)

various forms of consideration paid or conveyed to us, all of which have been received in prior years. As of June 30, 2014, we owned approximately 990,000 gross (425,000 net) developed and undeveloped acres in this play and had drilled or participated in the drilling of 244 wells since the inception of the joint venture.

Effective April 1, 2013, we entered into an amendment to the JDA with Chesapeake which, among other things, provided for (1) a redistribution of operatorship rights across the area of mutual interest (“AMI”) defined by the agreement, and (2) a limited farmout of our working interests in a defined number of wells to be drilled by Chesapeake. With the execution of the amendment, we became the named operator for approximately 460,000 gross acres, the majority of which is located in Converse County, Wyoming, north of a demarcation line defined by the amendment. Pursuant to the amendment and commencing April 1, 2013, we farmed-out our working interest in the next consecutive 85 wells (subject to certain conditions) to be drilled by Chesapeake on the acreage Chesapeake operated south of the demarcation line. Upon payout, as defined by the amendment, we would have reverted back into our full ownership in the farmed-out wells. As of June 30, 2014, a total of 75 wells had been drilled or were in the process of being drilled pursuant to the farmout agreement.

On June 20, 2014, we entered into an Exchange Agreement (the “Exchange Agreement”) with Chesapeake pursuant to which we agreed to convey (i) approximately 204,000 net non-operated acres and (ii) our non-operated working and net revenue interests in 191 wells, all of which are located south of the aforementioned demarcation line within the AMI defined by the JDA, in exchange for Chesapeake’s conveyance to us of (x) approximately 136,000 net operated acres, and (y) operated working and net revenue interests in 68 wells, all of which are located north of the demarcation line within the AMI, plus (z) a cash payment of $450 million, which was subject to normal closing adjustments. Estimated proved reserves associated with the oil and natural gas properties conveyed to Chesapeake totaled approximately 25.4 MMBoe as of December 31, 2013; estimated proved reserves associated with the oil and natural gas properties received from Chesapeake totaled approximately 2.2 MMBoe as of December 31, 2013. The Exchange Agreement closed on August 19, 2014 and we received net proceeds of approximately $438 million, which is also subject to normal post-closing adjustment. We presently own approximately 351,000 net acres in the Powder River Basin and we have operatorship control over the vast majority of this acreage. The cash proceeds from this transaction were used to pay down borrowings under our revolving bank credit facility and for working capital purposes. The JDA terminated upon closing.

Closing of the Exchange Agreement resulted in a gain recognition of $75.6 million, which was based on the estimated fair value of the oil and natural gas properties conveyed to Chesapeake as compared to the associated carrying value. This estimated fair value was then used for valuing the oil and natural gas properties received from Chesapeake in the exchange, net of the cash consideration. This resulted in non-cash proved and unproved oil and natural gas property additions of $52.2 million and $114.3 million, respectively. The fair values of proved and unproved oil and natural gas properties conveyed to Chesapeake were determined based on a third party valuation of the associated assets and liabilities, which we in turn deemed to be reasonable. The fair values of proved and unproved oil and natural gas properties acquired were determined through discounted cash flow analyses, analysis of available market data and management judgment. The valuation of proved and unproved oil and natural gas properties at a given point in time is subject to a wide range of highly variable assumptions, including commodity prices.

Delaware Basin Property Acquisition. On May 23, 2014, we closed on an acquisition of proved and unproved oil and natural gas properties located in the Delaware Basin of southeast New Mexico and southwest Texas from Chaparral Energy, L.L.C. (the “Chaparral Properties”). At closing, the Chaparral Properties contained an estimated 510 producing wells (289 of which were operated by us upon closing), 6.5 MMBoe of proved reserves, 1,850 Boed of production, 30 miles of natural gas gathering systems, and approximately 29,000 net acres. The majority of the acquired properties are in close proximity to our existing acreage position in the stateline area of New Mexico and Texas. We believe the Chaparral Properties are prospective for Delaware, Bone Spring and Wolfcamp development. The final purchase price was approximately $120 million. The acquisition was funded primarily through an advance on existing equity commitments from our investors and availability under our revolving bank credit facility.

The following table summarizes the estimated fair value of the oil and natural gas properties conveyed pursuant to the Powder River Basin Property Exchange, and the consideration paid for the Delaware Basin Property Acquisition, and the amounts of the identifiable assets acquired and liabilities assumed as of the respective closing dates for both transactions. Acquisition-related costs, all of which were included in general and administrative expenses in the accompanying income statement for the year ended December 31, 2014, were immaterial.

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Sale of Powder River Basin Acreage. On May 29, 2014, we closed on the sale of approximately 15,900 net undeveloped acres located in the northwest portion of Converse County, Wyoming. This acreage was located in an area of the Powder River Basin for which we did not have near-term development plans, situated outside of existing federal units. As consideration for this acreage, we received $57.0 million, plus approximately 4,200 net acres, also located in Converse County within our core development area, for an effective sales price of approximately $4,900 per net acre divested. This divestiture, which included 100% of our ownership in the acreage being conveyed, resulted in a gain recognition of $46.7 million. The cash proceeds were used to fund a portion of our 2014 drilling program.

$1.0 Billion Revolving Bank Credit Facility. On November 14, 2011, we entered into a Second Amended and Restated Credit Agreement with Citibank, N.A. as administrative agent. The agreement provided for up to $500 million in borrowings and letters of credit on a revolving basis; associated availability under the facility was equal to the lesser of $500 million or the borrowing base, as defined by the agreement. The borrowing base was redetermined on each March 1 and September 1 based on a periodic valuation of our oil and natural gas reserves, subject to certain adjustments. No principal payments were required under the facility until maturity on October 31, 2015.

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Notes to Consolidated Financial Statements (continued)

On February 26, 2014, we entered into the Sixth Amendment to Second Amended and Restated Credit Agreement with Citibank, N.A. as administrative agent. The terms of the amendment, among other things, increased the total facility size to $1.0 billion, increased the borrowing base under the facility from $425 million to $550 million, and increased the number of commercial banks participating in the facility from ten to thirteen. In addition, the maturity of the facility was extended to February 26, 2019. Pricing and redetermination dates under the amended agreement were unchanged from the previous facility. The facility was most recently amended on September 10, 2014, the terms of which increased the borrowing base under the facility to $670 million, and removed the existing limitation on the amount of additional senior unsecured indebtedness we can issue, subject to certain conditions.

The applicable interest rate for borrowings under the facility is subject to a pricing grid based on the amount of outstanding borrowings in relation to the borrowing base. We have the option to select either Eurodollar-based loans or prime rate-based loans. As of December 31, 2014 and 2013, the applicable interest rate margin for Eurodollar-based loans ranged from 175 to 275 basis points; the applicable margin for prime rate-based loans ranged from 75 to 175 basis points. The facility also provides for a commitment fee of 50 basis points payable on the difference between the total amount available for borrowing and actual outstanding indebtedness under the facility.

The facility contains various affirmative and restrictive covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, the payment of dividends, and require us to meet certain financial tests, including total debt to EBITDAX (as defined in the agreement), and EBITDAX to interest. We were in compliance with all of the financial tests required by the agreement as of December 31, 2014 and 2013. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings could be declared immediately due and payable. Borrowings under the facility are secured by mortgages on the vast majority of our proved oil and natural gas properties.

As of December 31, 2014, $290 million of principal and $775,000 face amount of letters of credit were outstanding under this facility, and approximately $379.2 million was available for borrowing. As of December 31, 2013, $250 million of principal and $825,000 face amount of letters of credit were outstanding under this facility, and approximately $174.2 million was available for borrowing. The effective rate for borrowings outstanding on December 31, 2014 and 2013 was 2.2% and 2.6%, respectively.

The amount of required principal payments as of December 31, 2014 is provided as follows: 2015 – $0; 2016 – $0; 2017 –$0; 2018 – $0, and thereafter – $290 million.

Second Lien Credit Agreement. On October 25, 2012, we entered into a Second Lien Credit Agreement with Citibank, N.A. as administrative agent. The facility provided for a single initial borrowing of the full facility amount of $120 million which was drawn October 25, 2012 in the form of a Eurodollar-based term loan. The borrowing was not revolving and was pari passu with the obligations under the existing $500 Million Revolving Bank Credit Facility, but subordinate to the priority claims on collateral assigned under the $500 Million Revolving Bank Credit Facility. No principal repayment was required by the agreement until maturity, which was October 25, 2018.

On February 27, 2013, we entered into a Commitment Increase Agreement, which provided for an increase in the loan commitments from $120 million to $170 million. This increase of $50 million was drawn on February 27, 2013. Interest rates and the maturity date associated with this facility were unchanged by the amendment. Under the terms of this facility, we had the option to select either Eurodollar-based loans or prime rate-based loans. The applicable interest rate for the Eurodollar-based borrowing under this facility was the adjusted LIBO rate for the interest period in effect for the borrowing plus the applicable margin. The adjusted LIBO rate was defined as the greater of 1.5% or the LIBO rate published by Reuters at the time of the borrowing; the applicable margin was 7.0%. The applicable margin for prime rate-based loans was 6.0%. On July 19, 2013, we repaid the outstanding principal with proceeds from the issuance of our 8.5% Senior Notes due 2021, and terminated the facility, resulting in the recognition of a $3.3 million loss.

8.5% Senior Notes due 2021. On July 18, 2013, we issued $350 million of 8.5% Senior Notes due 2021 pursuant to Rule 144A under the Securities Act of 1933. Interest on these notes is due on each February 1 and August 1. On July 26, 2013, we issued an additional $50 million of 8.5% Senior Notes (the July 18, 2013 issuance and the July 26, 2013 issuance collectively referred to as “8.5 % Senior Notes due 2021”). Net proceeds from the issuance of the 8.5% Senior Notes due 2021 totaled approximately $392.3 million. Approximately $9.1 million of associated issuance costs have

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Notes to Consolidated Financial Statements (continued)

been capitalized, which are being amortized over the life of the notes. The notes are senior unsecured obligations of RKI and RKI Finance Corp., a wholly owned subsidiary formed for the sole purpose of co-issuing the 8.5% Senior Notes due 2021. The notes are fully and unconditionally guaranteed on a senior unsecured basis by RKI’s existing subsidiaries (other than the co-issuer) and certain future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the $1.0 Billion Revolving Bank Credit Facility. As of December 31, 2014, the assets, liabilities, revenues and expenses of such subsidiaries were immaterial on a stand alone basis and in the aggregate. The proceeds from the issuance of these notes were used to retire outstanding principal and interest on the Second Lien Credit Facility and pay down outstanding principal under the revolving bank credit facility.

The associated indenture agreement contains various restrictive covenants, which among other things, limit additional indebtedness, the sale of assets, the payment of dividends, and other forms of restrictive payments as defined by the indenture. If we should fail to perform our obligations under these and other covenants, the 8.5% Senior Notes due 2021 could be declared immediately due and payable. We are in compliance with all such covenants as of December 31, 2014 and 2013.

A reconciliation of the provision for income taxes at the statutory federal tax rate to our actual provision for income taxes is as follows for the years ended December 31, 2014, 2013 and 2012:

Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent on the generation of future taxable income during the periods in which the temporary differences become deductible. Among other items, we consider the scheduled reversal of deferred tax liabilities, projected future taxable income and available tax planning strategies. Deferred tax assets are reduced by a valuation allowance when a determination is made that it is more likely than not that some or all of the deferred tax assets will not be realized based on the weight of all available evidence. As of December 31, 2014 and 2013, we determined that a valuation allowance against recorded deferred tax assets was not necessary.

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The deferred tax assets at December 31, 2014 do not include approximately $1.2 million of excess tax benefits from employee incentive shares which have vested and are a component of our tax net operating loss. Members’ equity will be increased by $1.2 million if and when such excess tax benefits are ultimately realized.

We will file a consolidated income tax return in the United States federal jurisdiction and in three states for the year ended December 31, 2014. The earliest year subject to examination is 2011.

As of December 31, 2014, we had a federal net operating loss carryforward of approximately $840 million, which will begin to expire in 2030. We have state net operating loss carryforwards aggregating approximately $13 million, the majority of which relates to New Mexico. These carryforwards begin to expire in 2015. In addition, we have a statutory depletion carryforward for federal income tax purposes of $2.6 million which will be recognized in the income tax provision when realized; this carryforward item does not expire.

Note 6 – TRANSACTIONS WITH RELATED PARTIES

We provide certain administrative costs and services on behalf of Prize Royalties, LLC, an affiliate. These services include an allocation of personnel costs, employee benefits, office expenses and other general and administrative expenses, all of which are billed to Prize Royalties, LLC at cost. The amounts billed to Prize Royalties, LLC for the years ended December 31, 2014, 2013 and 2012 were not material.

Certain of our investors, including the Chief Executive Officer, have separately made ownership investments in various third party service providers which from time to time provide us oil field and technology services. These service providers are selected for use on a competitive basis and the services provided are billed to us at market competitive rates. For the years ended December 31, 2014, 2013 and 2012, the aggregate amount paid to such providers totaled approximately $46.5 million, $6.6 million and $0, respectively.

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RKI E XPLORATION & P RODUCTION , LLC

Notes to Consolidated Financial Statements (continued)

Note 7 – COMMITMENTS AND CONTINGENCIES

We are a defendant in two wrongful death claims as of December 31, 2014. While the outcomes of these proceedings cannot be predicted with certainty, we do not believe they will have a material adverse effect on our financial position or results of operations. We do not have knowledge of any further threatened or pending litigation.

Rental Commitments. As of December 31, 2014, we are a party to two noncancellable leases for office space in Oklahoma City, Oklahoma, which expire March 31, 2016 and August 31, 2018, respectively. We are also party to two noncancellable leases for office space in Casper, Wyoming, which expire March 15, 2016 and July 31, 2016, respectively, and one noncancellable lease in Carlsbad, NM, which expires May 31, 2015. Remaining rent payments due under these leases are as follows: 2015 – $1,333,000; 2016 – $1,067,000; 2017 – $959,000 and 2018 – $639,000. Such minimum lease payments have not been reduced by minimum sublease rentals totaling $341,000 to be received under noncancellable subleases through March 31, 2016. Rent expense included in results of operations for the years ended December 31, 2014, 2013 and 2012 was approximately $1,193,000, $930,000 and $497,000, respectively. Sublease income included in results of operations for the years ended December 31, 2014, 2013 and 2012 was $264,000, $130,000 and $0, respectively.

Environmental Risk. We are exposed to possible environmental risks which are inherent with oil and natural gas drilling and production operations. We have implemented various policies and procedures to avoid environmental contamination and to minimize the associated risks. Our operated oil and natural gas properties are reviewed periodically for indications of environmental contamination or potential exposure. We have not experienced any significant environmental liability and we are not aware of any potential material environmental issues or claims at December 31, 2014.

Other. We are a party to a drilling rig contract which provides for penalties to the contractor under certain conditions upon an early termination prior to the contract expiration in September 2015. As of December 31, 2014, the remaining minimum commitment pursuant to this contract was approximately $5.1 million. We expect to utilize this rig in our Permian basin drilling operations through the contract term.

Note 8 – MEMBERS’ EQUITY

On October 27, 2011, we entered into a Securities Purchase Agreement with FR Rhino LLC (an investment vehicle of First Reserve Advisors XII, LLC, which is an investment fund managed by First Reserve Corporation), ZAM Ventures II, Inc. (an investment vehicle of Ziff Brothers Investments, LLC.), and two additional RKI members (collectively, the “Purchasers”) for the private placement and sale of an aggregate 2,076,725 shares at a price of $271.13 per share, to be funded as capital call notices are issued by the Board of Managers. On February 27, 2012, we entered into Amendment No. 1 to the Securities Purchase Agreement which provided the remaining RKI members who are “accredited investors” within the meaning of Rule 501 of Regulation D under the Securities Act of 1933 (the “Supplemental Purchasers”) the option to participate in the sale of shares and other transactions contemplated by the Securities Purchase Agreement. The amendment resulted in an irrevocable commitment of the Supplemental Purchasers to purchase an aggregate 11,513 shares at a price of $271.13 per share, to be funded as capital call notices are issued by the Board of Managers.

On February 8, 2013, we entered into a Securities Purchase Agreement with Alda Investment Pte Ltd (“Alda”) for a tack-on private placement and sale of an additional 553,240 shares at a price of $271.13 per share. Alda is wholly-owned by Government of Singapore Investment Corporation (Ventures) Private Limited. The Securities Purchase Agreement provides for an irrevocable commitment of Alda to purchase the shares as capital call notices are issued by the Board of Managers. In connection with the private placement, we amended our limited liability company agreement to increase the number of authorized shares to 7,013,515 and to provide certain rights to Alda pari passu with the Purchasers to the Securities Purchase Agreement dated October 27, 2011. On April 25, 2013, in connection with the execution of the Securities Purchase Agreement with Alda, the Supplemental Purchasers were provided an opportunity to exercise their anti-dilution rights extended to them by Amendment No. 1 to the Securities Purchase Agreement with FR Rhino LLC and ZAM Ventures II, Inc., et al. The Supplemental Purchasers committed to acquire an additional 8,434 shares of RKI at $271.13 per share.

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As of December 31, 2014, remaining shares to be issued and sold pursuant to the respective Securities Purchase Agreements, as amended, total 251,723 shares, representing a total undrawn equity commitment of approximately $68.2 million.

As of December 31, 2014, 7.0 million shares were authorized for issuance, 6.6 million shares were issued and outstanding and 20,189 shares were held as treasury shares. As of December 31, 2013, 7.0 million shares were authorized for issuance, 6.3 million of which were issued and outstanding. No cash distributions were made to our members during the years ended December 31, 2014 or 2013.

Note 9 – FAIR VALUE MEASUREMENTS

Certain of our assets and liabilities are reported at fair value in the accompanying consolidated balance sheets. The following table presents carrying value and fair value information for our financial assets and liabilities as of December 31, 2014 and December 31, 2013. Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. None of our financial assets and liabilities have Level 1 inputs as defined. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the financial asset or liability and have the lowest priority. We use appropriate valuation techniques based on available inputs, including counterparty quotes, to measure the fair values of our assets and liabilities.

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The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 2 Fair Value Measurements . The fair values of fixed-price oil and natural gas swaps are estimated using discounted cash flow calculations based upon forward market commodity prices as of the date of measurement. The discounted cash flow calculations are prepared by us using price inputs we review for propriety and are compared to counterparty quotations. Natural gas call options are based on third party market quotations as of the date of measurement.

Level 3 Fair Value Measurements . We review our oil and natural gas properties and other property and equipment used in operations whenever events or circumstances indicate the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value, based on discounted future cash flows. Estimating future cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. See Note 1 – Significant Accounting Policies – Property and Equipment.

Financial Instruments Not Measured at Fair Value. The carrying values of cash and cash equivalents, accounts receivable, accounts payable and other accrued liabilities included in the accompanying consolidated balance sheets are estimated to approximate fair value at December 31, 2014 and December 31, 2013 due to the short-term maturities of these instruments. Revolving bank debt and the 8.5% Senior Notes due 2021 are presented in the accompanying consolidated balance sheets at face value of the outstanding principal. The estimated fair value of the revolving bank debt as of December 31, 2014 and December 31, 2013 was $290 million and $250 million, respectively. The estimated fair value of the 8.5% Senior Notes due 2021 as of December 31, 2014 and December 31, 2013 was $323 million and $421 million. The estimated fair values of the revolving bank debt were based on internal discounted cash flow calculations using the estimated interest rate credit spreads available to us as if the revolving credit facility had been negotiated as of the respective date. The estimated interest rate credit spreads were derived from quotations from financial institutions. Such fair value measurement inputs are Level 3 inputs. The estimated fair value of the 8.5% Senior Notes due 2021 was based on market quotations which are deemed to be Level 2 inputs.

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RKI E XPLORATION & P RODUCTION , LLC

Notes to Consolidated Financial Statements (continued)

Note 10 – INTANGIBLE ASSETS

As of December 31, 2014, we had recorded $10.9 million of capitalized costs and fees, net of accumulated amortization, incurred in connection with the amendment of our revolving bank credit facility and the issuance of our 8.5% Senior Notes due 2021. See Note 4 – Long-term Debt. Such costs are being amortized over the respective lives of the two facilities. For the years ended December 31, 2014, 2013 and 2012, we recognized amortization expense of approximately $2.4 million, $1.6 million and $900,000, respectively, related to loan origination fees. The estimated future amortization expense related to intangible assets held at December 31, 2014 for the succeeding five years is as follows: 2015 – $2.5 million; 2016 – $1.8 million; 2017 – $1.8 million; 2018 – $1.8 million; 2019 – $1.2 million; and thereafter – $1.8 million.

In November 2009, approximately $3.0 million of goodwill was recognized in connection with the purchase of the third party ownership of an affiliate. This amount is not subject to amortization for US GAAP purposes, but is amortized over 15 years for federal income tax purposes. See Note 1 – Significant Accounting Policies – Goodwill.

Note 11 – DERIVATIVES

Description of Contracts. From time to time, we utilize fixed-price contracts to reduce exposure to unfavorable changes in oil and natural gas prices which are subject to significant and often volatile fluctuation. At December 31, 2014, these contracts consisted of fixed-price oil swaps, natural gas swaps and natural gas call options. The contracts allow us to predict with greater certainty the effective oil and natural gas prices to be received for production hedged by these contracts. However, we will not benefit from market prices that are higher than the fixed prices in these contracts for hedged production. For the years ended December 31, 2014, 2013 and 2012, fixed-price contracts hedged 49%, 62% and 53%, respectively, of our oil production and 55%, 20% and 0%, respectively, of our natural gas production.

For swap agreements, we receive a fixed price for the respective commodity and pay a floating market price, as defined in each contract, to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. For natural gas call options, if the market price of natural gas exceeds the call strike price, we receive the fixed price and pay the market price. If the market price of natural gas is below the call strike price, no payments are due from either party.

The following table summarizes the estimated future volumes, fixed prices, fixed-price sales and net revenues attributable to the fixed-price contracts we held as of December 31, 2014. We expect the prices to be realized for hedged production to vary from the prices shown in the following table due to basis, which is described under Market Risk below. Future net revenues for any period are determined as the differential between the fixed prices provided by fixed-price contracts and forward market prices as of December 31, 2014, as adjusted for basis. Future net revenues change with changes in market prices and basis. See “– Market Risk.” None of these contracts are used for trading purposes or activities.

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The estimates of future net revenues from fixed-price contracts are computed based on the difference between the prices provided by the fixed-price contracts and forward market prices as of the specified date. We have relied upon market quotations as of December 31, 2014 to determine future net revenue estimates. Forward market prices for oil and natural gas are dependent upon supply and demand factors in such forward markets and are subject to significant volatility. The future net revenue estimates shown above are subject to change as forward market prices change. See Note 9 – Fair Value Measurements. See Note 16 - Subsequent Events for a discussion of new oil swaps added in the first quarter of 2015.

Accounting. None of the fixed-price contracts in effect during the financial statement periods presented were designated as hedges for accounting purposes. Consequently, all changes in fixed-price contract fair value were recognized in results of operations for the respective fiscal period through December 31, 2014. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. The realized contract profit or loss is included in oil and natural gas sales in the period for which the underlying production was afforded price protection. The fair value of all fixed-price contracts are recorded as assets or liabilities in the consolidated balance sheet.

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RKI E XPLORATION & P RODUCTION , LLC

Notes to Consolidated Financial Statements (continued)

The following table presents the balance sheet location and presentation of our fixed-price contracts as of December 31, 2014 and December 31, 2013.

For the years ended December 31, 2014, 2013 and 2012, oil, natural gas and NGL gas sales included a loss of $1.8 million, a loss of $1.3 million and a gain of $3.3 million, respectively, associated with realized cash settlements under fixed-price contracts. Change in fixed-price commodity contract fair value for the years ended December 31, 2014, 2013 and 2012, reflected a gain of $83.1 million, a loss of $4.5 million, and a gain of $11.0 million, respectively, all associated with changes in fair value for derivatives not designated as cash flow hedges for accounting purposes. Such amounts do not represent cash gains or losses, but rather are temporary valuation swings in the associated contract. All gains or losses recorded in this caption are ultimately reversed within this same caption over the lives of the respective contracts.

Credit Risk. The terms of the fixed-price contracts provide for net settlements due to or from the respective party on a monthly basis. If the counterparty to our contracts should default when the contract fair values are greater than zero, there can be no assurance that we would be able to recover the fair value of the contract or be able to enter into a new contract with a third party on terms comparable to the original contract. We have not experienced non-performance by any counterparty. Cancellation or termination of a fixed-price contract would subject a greater portion of our oil and natural gas production to market prices, which, in a low price environment could have an adverse effect on our operating results. The counterparties to our fixed-price contracts are banks in the $1.0 Billion Revolving Bank Credit Facility.

Market Risk. The differential between the floating price paid under each fixed-price contract and the price received at the wellhead for our production is termed “basis” and is the result of differences in location, quality, contract terms, timing and other variables. The effective price realizations which result from the fixed-price contracts are affected by movements in basis. Basis movements can result from a number of variables, including regional supply and demand factors. Basis movements are generally considerably less than the price movements affecting the underlying commodity, but their effect can be significant. From time to time, the floating price index defined in the fixed-price contracts has been selected as a means to manage the exposure to basis movements.

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RKI E XPLORATION & P RODUCTION , LLC

Notes to Consolidated Financial Statements (continued)

Gains and losses to be realized in oil and natural gas sales upon cash settlements of fixed-price contracts are expected to be offset by changes in the price received for our oil and natural gas production. Because a portion of our future oil and natural gas production is presently unhedged, declining oil and natural gas prices could have a material adverse effect on future results of operations and operating cash flows.

Margin. The terms of the fixed-price contracts do not provide for margin requirements for either party. However, the contracts are cross-collateralized by the oil and natural gas properties mortgaged under the $1.0 Billion Revolving Bank Credit Facility.

Note 12 – EMPLOYEE BENEFIT PLANS AND SHARE-BASED COMPENSATION

401(k) Plan. All full-time employees are eligible to participate in our 401(k) Plan which was formed effective January 1, 2007. Pursuant to the plan provisions, employee contributions can be made to the plan up to the maximum percentage allowable by law. We match employee contributions up to 6% of the respective employee’s salary. Employees vest 100% in employer contributions upon entering the plan. Our contributions to the 401(k) Plan totaled approximately $719,000, $433,000 and $315,000 for the years ended December 31, 2014, 2013 and 2012, respectively.

Employee Incentive Shares. For the years ended December 31, 2014 and 2013, 79,150 shares and 70,875 shares, respectively, were granted to our board members and employees. Such shares vest over a four to five year period. An additional 143,185 shares are reserved for issuance under this plan. The fair value of the share grants is recognized pro rata as compensation expense over the respective vesting period, included in general and administrative expense in the consolidated statement of income. For the years ended December 31, 2014, 2013, and 2012, we recognized approximately $11.7 million, $6.9 million and $4.1 million, respectively, of compensation expense related to incentive share grants.

A summary of the status of RKI’s nonvested incentive shares as of December 31, 2014, 2013 and 2012, and related changes during the years then ended, is presented below.

As of December 31, 2014, there was $36.9 million of total unrecognized compensation cost related to nonvested incentive shares issued to employees. That cost is expected to be recognized over a weighted average of 3.5 years. The total fair value of shares vested during the years ended December 31, 2014, 2013 and 2012 was $11.4 million, $7.9 million and $5.3 million, respectively. The fair market value of the incentive share awards shown in the preceding table are based on our estimated enterprise value at the date of grant, with consideration given to rights and terms of such shares issued relative to the rights and terms of shares held by other shareholders, as appropriate. Forfeitures were estimated at 2% and no dividends are assumed in the fair value calculation. We rely upon third party valuations and near-term sales of shares to third parties in estimating our enterprise value.

Note 13 – SIGNIFICANT CUSTOMERS

Our oil and natural gas is sold under contracts containing market sensitive pricing provisions with various purchasers. For the year ended December 31, 2014, sales to Shell Trading Company, Nuevo Midstream, LLC and Chesapeake Operating, Inc. accounted for approximately 23%, 10% and 10%, respectively, of total revenues. For the year ended December 31, 2013, sales to Shell Trading Company and Chesapeake Operating, Inc. accounted for approximately 30% and 21%, respectively, of total revenues. For the year ended December 31, 2012, sales to Shell

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RKI E XPLORATION & P RODUCTION , LLC

Notes to Consolidated Financial Statements (continued)

Trading Company and Chesapeake Operating Inc. accounted for 36% and 23%, respectively, of total revenues. We believe that alternative purchasers are available, if necessary, to purchase our production at pricing terms similar to those received during 2014. All amounts due from these purchasers were received subsequent to the respective year-end. No other purchaser accounted for as much as 10% of our total revenues.

Note 15 – SUPPLEMENTAL INFORMATION - OIL, NATURAL GAS AND NGL RESERVES (unaudited)

The following information summarizes our net proved reserves and discounted present values of oil, natural gas and NGL reserves as of December 31, 2014, 2013 and 2012. This information was derived from reserve engineering studies prepared in accordance with regulations prescribed by the SEC by an independent engineering firm. Future net revenues have been estimated by the independent engineering firm using an average of the oil, natural gas and NGL prices in effect on the first day of the preceding 12 months. Future operating costs estimated in the studies for all periods presented are based on historical operating costs incurred.

The reliability of any reserve estimate is a function of the quality of available information and of engineering interpretation and judgment. Such estimates are susceptible to revision in light of subsequent drilling and production history or as a result of changes in economic conditions.

Estimated Quantities of Oil, Natural Gas and NGL Reserves. The following table presents our estimated proved reserves as of December 31, 2014, 2013 and 2012. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGL which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that can be expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are generally limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

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