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Summary of Significant Accounting Policies | 12 Months Ended
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Dec. 31, 2015
Accounting Policies [Abstract] |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Basis of Presentation The accompanying Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The consolidated financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries, as well as BRP LLC ("BRP"), a joint venture with International Paper Company controlled by the Partnership. The Partnership has an equity investment through which it is able to exercise significant influence over but does not control the investee and is not the primary beneficiary of the investee’s activities which is accounted for using the equity method. Intercompany transactions and balances have been eliminated. Management’s Forecast, Strategic Plan and Going Concern Analysis While NRP has a diversified portfolio of assets and a history and continued forecast of profitable operations with positive operating cash flows, its operating results and credit metrics continue to be impacted by demand challenges for coal and excess worldwide supply of oil and gas. In particular, as described in Note 10. Debt and Debt—Affiliate, NRP Oil and Gas and NRP Opco have debt agreements that contain customary financial covenants, including maintenance covenants, and other covenants. In addition, NRP has issued $425 million of 9.125% Senior Notes that are governed by an indenture ("the Indenture") containing customary incurrence-based financial covenants and other covenants, but not maintenance covenants. The following discussion presents management’s going concern analysis in light of management’s outlook and strategic plan to address its debt covenant compliance and maturities. Opco and NRP As of December 31, 2015, Opco had $290.0 million of indebtedness outstanding under its revolving credit facility due October 2017 (the "Opco Credit Facility") and $585.9 million outstanding under several series of Private Placement Notes (the "Opco Private Placement Notes") (collectively referred to as the "Opco Debt agreements"). The maximum leverage ratio under the Opco Debt agreements is required to be below 4.0 x through March 31, 2016. Commencing with respect to the period ended June 30, 2016, the maximum leverage ratio reduces to 3.75 x and reduces again to 3.5 x commencing with respect to the period ended June 30, 2017. In addition, the Opco Debt agreements contain certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. As of December 31, 2015, Opco was in compliance with and we forecast that Opco will continue to remain in compliance through December 31, 2016 with the covenants contained in its debt agreements. In addition, we believe Opco has sufficient liquidity to make all regularly scheduled principal and interest payments through December 31, 2016. We are currently pursuing or considering a number of actions including (i) dispositions of assets, (ii) actively managing our debt capital structure through a number of potential alternatives, including exchange offers and non-traditional debt financing, (iii) minimizing our capital expenditures, (iv) obtaining waivers or amendments from our lenders, (v) effectively managing our working capital and (vi) improving our cash flows from operations. While we forecast that we will be in compliance with all of the covenants under the Opco Debt agreements through December 31, 2016, our forecast is sensitive to commodity pricing and counterparty risk. Accordingly, management intends to pursue one or more of the alternatives discussed above in order to mitigate the effects of further commodity price and market deterioration which could otherwise cause us to breach financial covenants under the Opco Debt agreements. Breaches of the Opco Debt agreement covenants that are not waived or cured, to the extent possible, would result in an event of default under the Opco Debt agreements, and if such debt is accelerated by the lenders thereunder, such acceleration would also result in a cross-default under the Indenture. NRP Oil and Gas NRP Oil and Gas had $85.0 million outstanding under its senior secured, reserve-based revolving credit facility (the "RBL Facility") as of December 31, 2015. The facility is secured by a first priority lien on substantially all of NRP Oil and Gas’s assets and is not guaranteed by NRP or any other subsidiary of NRP. Due to the significant and sustained decline in oil prices since the end of 2014, management forecasts that NRP Oil and Gas may not be able to remain in compliance with the 3.5 x leverage ratio as required in the RBL Facility during the next 12 months. In addition, management expects that, due to current oil and gas prices, the next borrowing base redetermination under the RBL Facility that is scheduled to occur in May 2016 may result in a reduction of the borrowing base by an amount that would exceed NRP Oil and Gas’s ability to repay principal within the required time-frame following such redetermination. In addition, the RBL Facility requires the entity to provide annual financial statements that include a report from its independent registered public accounting firm with an opinion that does not contain "a "going concern" or like qualification or exception." Any of these events would qualify as an event of default and would provide the RBL Facility lenders with the ability to accelerate the debt outstanding under the RBL Facility to the extent not waived or cured. While we are attempting to take appropriate mitigating actions, there is no assurance that any particular actions with respect to amending, refinancing, extending the maturity or curing potential defaults in the RBL Facility will be sufficient, and we may be required to sell some or all of the assets of NRP Oil and Gas, raise new equity capital at NRP Oil and Gas or pursue restructuring alternatives. As a result, we believe there is substantial doubt about the ability of NRP Oil and Gas to continue as a going concern through December 31, 2016. As we were in compliance with all covenants contained in the RBL Facility throughout 2015 and at December 31, 2015, we have classified this debt as non-current in accordance with its terms. An event of default under the RBL facility and subsequent acceleration of that debt by the lenders thereunder would not result in a cross-default under the Indenture. NRP Oil and Gas is designated as an "Unrestricted Subsidiary" for purposes of the Indenture, which prevents an event of default under the RBL Facility and subsequent acceleration of that debt from triggering an event of default under the Indenture. In addition, there are no cross-defaults under the Opco Debt agreements as a result of a default under the RBL Facility. As a result, there would be no default or acceleration of indebtedness under the Indenture or under the Opco Debt agreements in the event NRP Oil and Gas is in default under its RBL Facility. Recasting of Certain Prior Period Information Due to the acquisitions that diversified our natural resource asset base, effective for the quarter ended December 31, 2015, management revised the Partnership's operating segments to align with its management structure and organizational responsibilities and revised the information that its chief operating decision maker regularly reviews for purposes of allocating resources and assessing performance. As a result, effective for the quarter ended December 31, 2015, we report our financial performance based on new segments as described in "Note 3. Segment Information". We recast certain prior period amounts to conform to the way we internally manage and monitor segment performance. This change had no impact on the Partnership's consolidated financial position, net income (loss) or cash flows. In addition, certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation. Prior year general and administrative charges that were allocated to the operating segments have been reclassified to Operating and maintenance expenses and Operating and maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Reverse Unit Split On January 26, 2016, the board of directors of our general partner approved a 1-for-10 reverse split on our common units, effective following market close on February 17, 2016. Pursuant to the authorization provided, the Partnership completed the 1-for-10 reverse unit split and its common units began trading on a reverse unit split-adjusted basis on the New York Stock Exchange on February 18, 2016. As a result of the reverse unit split, every 10 outstanding common units were combined into one common unit. The reverse unit split reduced the number of common units outstanding from 122.3 million units to approximately 12.2 million units. All units and per unit data included in these consolidated financial statements have been retroactively restated to reflect the reverse unit split. Use of Estimates Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the accompanying Consolidated Balance Sheets and the reported amounts of revenues and expenses in the accompanying Consolidated Statements of Comprehensive Income during the reporting period. Actual results could differ from those estimates. Business Combinations For purchase acquisitions accounted for as business combinations, the Partnership is required to record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques. Out-of-Period Adjustment In March 2015, the Partnership recorded an out-of-period adjustment to correct an error in depletion expense related to its oil and gas royalty interests owned by BRP, in which the Partnership owns a 51% interest. Depletion expense for the year ended December 31, 2015 includes a credit of $3.8 million to adjust the impact of depletion expense recorded in prior periods. After evaluating the quantitative and qualitative aspects of the error and the out-of-period adjustment to the Partnership’s financial results, management determined the misstatement and the out-of-period adjustment are not material to the prior period financial statements. Fair Value The Partnership discloses certain assets and liabilities using fair value as defined by authoritative guidance. Fair value is defined as 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. See "Note 11. Fair Value Measurements." There are three levels of inputs that may be used to measure fair value:
• | Level 1—Quoted prices in active markets for identical assets or liabilities.
• | Level 2—Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
• | Level 3—Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation.
Cash and Cash Equivalents The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents. Accounts Receivable Accounts receivable from the Partnership’s lessees and customers do not bear interest. Receivables are recorded net of the allowance for doubtful accounts in the accompanying Consolidated Balance Sheets. The Partnership evaluates the collectability of its accounts receivable based on a combination of factors. The Partnership regularly analyzes its accounts receivable and when it becomes aware of a specific lessee’s or customer’s inability to meet its financial obligations to the Partnership, such as in the case of bankruptcy filings or deterioration in the lessee’s or customer’s operating results or financial position, the Partnership records a specific reserve for bad debt to reduce the related receivable to the amount it reasonably believes is collectible. The reserve is recognized as a reduction in the accounts receivable and an increase in operating and maintenance expenses or operating and maintenance expenses—affiliates. Accounts are charged off when collection efforts are complete and future recovery is doubtful. The allowance for doubtful accounts included in the Partnership's net accounts receivable balance (including affiliates) was $5.3 million and $0.7 million at December 31, 2015 and December 31, 2014, respectively. A significant amount of the change to the Partnership's allowance for doubtful accounts during 2015 relates to new allowances for doubtful coal-related receivables. Inventory Inventories are stated at the lower of cost or market. The cost of aggregates and asphalt components such as stone, sand, and recycled and liquid asphalt is determined by the first-in, first-out (FIFO) method. Cost includes all direct materials, direct labor and related production overheads based on normal operating capacity. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Partnership’s aggregates operations. Plant and Equipment Plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the asset acquired and consists of coal preparation plants, related coal handling facilities, and other coal and aggregate processing and transportation infrastructure. Expenditures for new facilities and expenditures that substantially increase the useful life of property, including interest during construction, are capitalized and reported in the Consolidated Statements of Cash Flows. These assets are recorded at cost and are depreciated on a straight-line basis over their useful lives generally as follows:
| Years
Buildings and improvements | 20 to 40
Machinery and equipment | 5 to 12
Leasehold improvements | Life of Lease
The Partnership begins capitalizing mine development costs at its aggregates operations at a point when reserves are determined to be proven or probable, economically mineable and when demand supports investment in the market. Capitalization of these costs ceases when production commences. Mine development costs are amortized based on production over the estimated life of mineral reserves and amortization is included as a component of depreciation expense. Mineral Rights Mineral rights owned and leased are recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. Coal and aggregate mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein. The Partnership owns royalty and non-operated working interests in oil and natural gas reserves, all of which are located in the U.S. The Partnership does not determine whether or when to develop reserves. The Partnership uses the successful efforts method to account for its working interest in oil and gas properties. Oil and gas non-operated working interests are depleted on a unit-of-production basis. The depletion rate is adjusted annually based upon the amount of remaining reserves as determined by independent third party petroleum engineers. Oil and gas royalty interests are depleted on a straight-line basis over 30 years or the life of the asset, whichever is shorter. Intangible Assets The Partnership’s intangible assets consist primarily of contracts that at acquisition were more favorable for the Partnership than prevailing market rates, known as above-market contracts. The estimated fair values of the above-market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis except that a minimum amortization is calculated on a straight-line basis for temporarily idled assets. Asset Impairment We have developed procedures to periodically evaluate our long-lived assets for possible impairment. These procedures are performed throughout the year and are based on historic, current and future performance and are designed to be early warning tests. If an asset fails one of the early warning tests, additional evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition is less than the assets’ carrying value. Impairment is measured based on the estimated fair value, which is usually determined based upon the present value of the projected future cash flow compared to the assets’ carrying value. We believe our estimates of cash flows and discount rates are consistent with those of principal market participants. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require a separate impairment evaluation be completed on a significant property. As a result of the continued weakness in the coal markets and the potential for further declines in oil and natural gas prices, we intend to closely monitor our coal and oil and gas assets, and the impairment evaluation process may be completed more frequently if deemed necessary. Future impairment analyses could result in downward adjustments to the carrying value of our assets. During 2015, we recorded impairment expense of $676.1 million on certain of our mineral rights within our Coal, Hard Mineral Royalty and Other and Oil and Gas segments as well as plant and equipment within our Coal, Hard Mineral Royalty and Other and VantaCore segments. We evaluate our equity investments for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. In accordance with FASB accounting and disclosure guidance for goodwill, we test our recorded goodwill for impairment annually or more often if indicators of potential impairment exist, by determining if the carrying value of a reporting unit exceeds its estimated fair value. Factors that could trigger an interim impairment test include, but are not limited to, underperformance relative to historical or projected future operating results or significant changes in our overall business, industry, or economic trends. We recorded a $5.5 million impairment loss related to the VantaCore reporting unit for the year ended December 31, 2015. Revenue Recognition Coal, Hard Mineral Royalty and Other Revenues. Coal and hard mineral royalty revenues are recognized on the basis of tons of mineral sold by our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell. Processing fees are recognized on the basis of tons of material processed through the facilities by our lessees and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Other revenues include transportation and processing fees. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, we receive a fixed price per ton for all material transported on the beltlines. Most of the Partnership’s coal and aggregates lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue when received. The deferred revenue attributable to the minimum payment is recognized as revenue based upon the underlying mineral lease when the lessee recoups the minimum payment through production or in the period immediately following the expiration of the lessee’s ability to recoup the payments. Soda Ash Revenues. We account for non-marketable investments using the equity method of accounting if the investment gives us the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. We account for our investment in Ciner Wyoming using this method. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of the fair value of the underlying net assets of equity method investees is hypothetically allocated first to identified tangible assets and liabilities, then to finite-lived intangibles or indefinite-lived intangibles and the balance is attributed to goodwill. The portion of the basis difference attributed to net tangible assets and finite-lived intangibles is amortized over its estimated useful life while indefinite-lived intangibles, if any, and goodwill are not amortized. The amortization of the basis difference is recorded as a reduction of earnings from the equity investment in the Consolidated Statements of Comprehensive Income. Our carrying value in Ciner Wyoming is reflected in the caption "Equity in unconsolidated investments" in our Consolidated Balance Sheets. Our adjusted share of the earnings or losses of Ciner Wyoming is reflected in the Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity in earnings of Ciner Wyoming." These earnings are generated from natural resources, which are considered part of our core business activities consistent with its directly owned revenue generating activities. Investee earnings are adjusted to reflect the amortization of any difference between the cost basis of the equity investment and the proportionate share of the investee’s book value, which has been allocated to the fair value of net identified tangible and finite-lived intangible assets and amortized over the estimated lives of those assets. VantaCore Revenues. Revenues from the sale of aggregates, gravel, sand and asphalt are recorded based upon the transfer of product at delivery to customers, which generally occurs at the quarries or asphalt plants. Revenues from long-term construction contracts are recognized on the percentage-of-completion method, measured by the percentage of total costs incurred to date to the estimated total costs for each contract. That method is used since we consider total cost to be the best available measure of progress on the contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions and estimated profitability, including those arising from final contract settlements, which result in revisions to job costs and profits are recognized in the period in which the revisions are determined. Contract costs include all direct job costs and those indirect costs related to contract performance, such as indirect labor, supplies, insurance, equipment maintenance and depreciation. General and administrative costs are charged to expense as incurred. Oil and Gas Revenues. Oil and gas related revenues consist of revenues from our non-operated working interests, royalties and overriding royalties. Revenues related to our non-operated working interests in oil and gas assets are recognized on the basis of our net revenue interests in hydrocarbons produced. Our revenues fluctuate based on changes in the market prices for oil and natural gas, the decline in production from producing wells, and other factors affecting the third-party oil and natural gas exploration and production companies that operate our wells, including the cost of development and production. Oil and gas royalty revenues are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Also, included within oil and gas royalties are lease bonus payments, which are generally paid upon the execution of a lease. Property Taxes The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The payment of and reimbursement of property taxes is included in Coal, Hard Mineral Royalty and Other revenues and in Operating and maintenance expenses, respectively, in the Consolidated Statements of Comprehensive Income. Transportation Revenue and Expense The Company records transportation revenue and pays transportation costs to a Foresight affiliate to operate equipment on behalf of the Company. The revenue and expenses related to these transactions are recorded as Coal, Hard Mineral Royalty and Other—affiliates revenues and Operating and maintenance expenses—affiliates in the Consolidated Statements of Comprehensive Income. Shipping and handling costs invoiced to aggregate customers and paid to third-party carriers are recorded as Coal, Hard Mineral Royalty and Other revenues and Operating and maintenance expenses in the Consolidated Statements of Comprehensive Income. Asset Retirement Costs and Obligations The Partnership accrues for mine closure, reclamation as well as plugging and abandonment of its oil and gas non-operated working interests in accordance with authoritative guidance related to accounting for asset retirement costs and obligations. This guidance requires the fair value of an obligation be recognized in the period it is incurred, if the fair value can be reasonably estimated. The Partnership recognizes an asset and liability related to the present value of future estimated costs. Depreciation or depletion of the capitalized asset retirement cost is determined based upon the underlying asset being retired in the future. Accretion of the asset retirement obligation is recognized over time and will increase as the obligation becomes more near term. It is reasonably possible that the estimates related to asset retirement and environmental obligations may change in the future. See "Note 13. Asset Retirement Obligations." Unit-Based Compensation We have awarded unit-based compensation in the form of phantom units that are more fully described in Note 16. Long-Term Incentive Plans." A summary of our accounting policy for unit-based awards follows. The Partnership accounts for awards relating to its Long-Term Incentive Plan using the fair value method, which requires the Partnership to estimate the fair value of the grant, and charge or credit the estimated fair value to expense over the requisite service period of the grant based on fluctuations in the Partnership’s common unit price. In addition, estimated forfeitures are included in the periodic computation of the fair value of the liability and the fair value is recalculated at each reporting date over the service or vesting period of the grant. See "Note 16. Long-Term Incentive Plans." Deferred Financing Costs Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s long-term debt. These costs are amortized over the term of the debt. Deferred financing costs are included in Other Assets on the Partnership's Consolidated Balance Sheets. Income Taxes No provision for income taxes related to the operations of the Partnership has been included in the accompanying financial statements because, as a partnership, it is not subject to federal or material state income taxes and the tax effect of its activities accrues to the unitholders. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities. Lessee Audits and Inspections The Partnership periodically audits lessee information by examining certain records and internal reports of its lessees. The Partnership’s regional managers also perform periodic mine inspections to verify that the information that has been reported to the Partnership is accurate. The audit and inspection processes are designed to identify material variances from lease terms as well as differences between the information reported to the Partnership and the actual results from each property. Audits and inspections, however, are in periods subsequent to when the revenue is reported and any adjustment identified by these processes might be in a reporting period different from when the revenue was initially recorded. Typically there are no material adjustments from this process. Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board ("FASB") amended its guidance on revenue recognition. The core principle of this amendment is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted for reporting periods beginning after December 15, 2016, including interim reporting periods within that period. This guidance can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows. In August 2014, the FASB issued guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. The new guidance will require a formal assessment of going concern by management based on criteria prescribed in the new guidance, but will not impact the Partnership's financial position or results of operations. The Partnership is reviewing its policies and processes to ensure compliance with this new guidance. In April 2015, the FASB issued authoritative guidance which intended to simplify the presentation of debt issuance costs in financial statements. This guidance requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This guidance is effective for annual reporting periods beginning after December 15, 2016. Early adoption is permitted. This guidance will be applied retrospectively to each prior period presented. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated balance sheets. In July 2015, the FASB issued authoritative guidance which intended to simplify the measurement of inventory. This guidance requires an entity to measure inventory at the lower of cost or net realizable value. The amendments do not apply to inventory that is measured using last-in, first-out or the retail inventory method. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with early adoption permitted. This guidance should be applied on a prospective basis. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows. In February 2016, FASB issued authoritative lease guidance that establishes a right-of-use ("ROU") model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The main difference between the current requirement under GAAP and the ROU model is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows.

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