FELP Foresight Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization, Nature of Business and Basis of Presentation

Foresight Energy LLC (“FELLC”), a perpetual-term Delaware limited liability company, was formed in September 2006 for the development, mining, transportation and sale of coal. Prior to June 23, 2014, Foresight Reserves LP (“Foresight Reserves”) owned 99.333% of FELLC and a member of FELLC’s management owned 0.667%. On June 23, 2014, in connection with the initial public offering (“IPO”) of Foresight Energy LP (“FELP”), Foresight Reserves and a member of management contributed their ownership interests in FELLC to FELP for which they were issued common and subordinated units in FELP. FELP has been managed by Foresight Energy GP LLC (“FEGP”) subsequent to the IPO.

On April 16, 2015, Murray Energy Corporation and its subsidiaries and affiliates (“Murray Energy”) and Foresight Reserves completed a transaction whereby Murray Energy acquired a 34% voting interest in FEGP and all of the outstanding subordinated units of FELP, representing a 50% ownership of the Partnership’s limited partner units outstanding at that time. On March 28, 2017, Murray Energy acquired an additional 46% voting interest in FEGP, thereby increasing Murray Energy’s voting interest in FEGP to 80%.

As used hereafter in this report, the terms “Foresight Energy LP,” “FELP,” the “Partnership,” “we,” “us” or like terms, refer to the consolidated results of Foresight Energy LP and its consolidated subsidiaries and affiliates, unless the context otherwise requires or where otherwise indicated.

The Partnership operates in a single reportable segment and currently owns four underground mining complexes in the Illinois Basin: Williamson Energy, LLC (“Williamson”); Sugar Camp Energy, LLC (“Sugar Camp”); Macoupin Energy, LLC (“Macoupin”); and Hillsboro Energy, LLC (“Hillsboro”). Mining operations at our Hillsboro complex had been idled since March 2015 due to a combustion event (the “Hillsboro Combustion Event”). In January 2019, we resumed production and development activities at our Hillsboro complex with one continuous miner unit.  Our mined coal is sold to a diverse customer base, including electric utility and industrial companies primarily in the eastern half of the United States, as well as overseas markets.

The accompanying condensed consolidated financial statements contain all significant adjustments (consisting of normal recurring accruals) that, in the opinion of management, are necessary to present fairly, the Partnership’s condensed consolidated financial position, results of operations and cash flows for all periods presented. In preparing the condensed consolidated financial statements, management used estimates and assumptions that may affect reported amounts and disclosures. To the extent there are material differences between the estimates and actual results, the impact to the Partnership’s financial condition or results of operations could be material. The unaudited condensed consolidated financial statements do not include footnotes and certain financial information as required annually under U.S. generally accepted accounting principles (“U.S. GAAP”) and, therefore, should be read in conjunction with the annual audited consolidated financial statements for the year ended December 31, 2018 included in our Annual Report on Form 10-K filed with the SEC on February 27, 2019. The results of operations for interim periods are not necessarily indicative of results that can be expected for any future period, including the year ending December 31, 2019. Intercompany transactions are eliminated in consolidation.

Liquidity, Capital Resources, Debt Obligations, and Potential Going Concern Considerations

The Partnership’s primary sources of liquidity consist of cash generated from operations, cash on hand, and a $170.0 million revolving credit facility (the “Revolving Credit Facility”).  As of September 30, 2019, we had $42.3 million of cash on hand and no meaningful borrowing availability under the Revolving Credit Facility.  Outstanding borrowings and letters of credit under the Revolving Credit Facility were $157.0 million and $12.3 million, respectively, as of September 30, 2019.

On October 1, 2019, FELLC and Foresight Energy Finance Corporation (together, the “Issuers”), wholly owned subsidiaries of the Partnership, elected to exercise the grace period with respect to the interest payment due under the indenture (the “Indenture”) governing the Issuers’ 11.50% Second Lien Senior Secured Notes due 2023 (the “Second Lien Notes due 2023”).  The election to exercise the grace period extended the time period the Issuers have to make the approximately $24.4 million interest payment without triggering an event of default under the Indenture.  

On October 23, 2019, the Issuers sought the consent of the holders (the “Holders”) of the Second Lien Notes due 2023 to amend (such amendments, the “Amendments”) the Indenture and sought the consent of the Holders to waive (such waiver, the “Waivers”) certain Defaults or Events of Defaults arising under the Indenture, in each case, as more fully described below.

As of October 30, 2019, the Issuers received consents to the amendments from Holders of at least a majority in aggregate principal amount of the outstanding Second Lien Notes due 2023 not owned by the Issuers or their affiliates. As a result, on October 30, 2019,

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the Issuers, the guarantors party thereto and Wilmington Trust, National Association, the trustee for the Second Lien Notes due 2023, entered into a supplemental indenture (the “Supplemental Indenture”) providing for the Amendments to the Indenture.

The Amendments (i) amend Section 6.01(b) of the Indenture to extend the grace period for payment of interest due on the Second Lien Notes due 2023 from 30 days to 90 days and (ii) amend Section 4.03(d) of the Indenture to exclude the fiscal period ended September 30, 2019 from the requirement that the Issuers hold a publicly accessible conference call to discuss the Issuers’ financial information for the relevant fiscal period.

As of October 30, 2019, Holders of at least a majority in aggregate principal amount of the outstanding Second Lien Notes due 2023 not owned by the Issuers or their affiliates also delivered Waivers that waived any Default or Event of Default, including under Section 6.01(b) of the Indenture, arising as a result of the Issuers’ failure to make the interest payment that was due to be paid by the Issuers on October 1, 2019.  The Waivers did not waive any obligation of the Issuers to make such payment of interest, or the right of any Holder to receive such payment (including as contemplated by Section 6.07 of the Indenture).  

The credit agreement governing our Credit Facilities requires that we comply on a quarterly basis with a maximum net first lien secured leverage ratio, currently 3.50:1.00 and stepping down by 0.25x in the first quarter 2021, which financial covenant is solely for the benefit of the lenders under the Revolving Credit Facility.  We were in compliance with the maximum net first lien secured leverage ratio as of September 30, 2019.  However, if current economic and market conditions persist, we can offer no assurance that we will be in compliance with all obligations and covenants measured as of future quarterly periods within the next 12 months or that we will be able to obtain waivers or other relief from the applicable lenders under the Credit Facilities, as necessary.  If we are unable to obtain waivers or other relief, the Partnership would be in default under the Revolving Credit Facility.  In such event, the lenders under the Revolving Credit Facility may immediately declare all outstanding indebtedness under the Revolving Credit Facility due and payable.  After such declaration, the lenders under the Term Loan due 2022 could immediately declare all indebtedness under the Term Loan due 2022 due and payable.  

The Partnership continues to engage in discussions with its creditor constituencies and is exploring potential restructuring alternatives.  As a result of these discussions and potential restructuring efforts, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in order to implement a restructuring, or our creditors, under certain circumstances, could force us into an involuntary bankruptcy or liquidation. If a plan of reorganization is implemented in a bankruptcy proceeding, it is likely that holders of claims and interests with respect to, or rights to acquire our equity securities, would likely be entitled to little or no recovery, and those claims and interests would likely be canceled for little or no consideration. If that were to occur, we anticipate that all, or substantially all, of the value of all investments in our partnership units would be lost and that our unitholders would lose all or substantially all of their investment. It is also likely that our other stakeholders, including our secured and unsecured creditors, could receive substantially less than the amount of their claims.

During the three and nine months ended September 30, 2019, we incurred legal and financial advisor fees of $1.2 million related to the above issues, which have been recorded as debt restructuring costs in the condensed consolidated statements of operations.  We expect legal and financial advisor fees to continue to be substantial until such time as the above issues are remediated, if at all.  

The conditions and circumstances above raise substantial doubt about the Partnership’s ability to continue as a going concern.  The condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount of and classification of liabilities that may result should the Partnership be unable to continue as a going concern.

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2. New Accounting Standards

In February 2016, the FASB updated guidance regarding the accounting for leases (the “New Lease Guidance”). The New Lease Guidance requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The New Lease Guidance also expands the required quantitative and qualitative disclosures surrounding leases. The New Lease Guidance is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years.

We adopted the New Lease Guidance as of January 1, 2019 using a modified retrospective transition approach for leases existing at, or entered into after, the adoption date.  Under this transition approach, comparative information for periods prior to January 1, 2019 is not adjusted. Upon adoption, we elected the package of practical expedients permitted under the New Lease Guidance, which allows for the carry forward of historical lease classification.  We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements.   

The adoption of the New Lease Guidance resulted in the addition of $7.6 million in lease right-of-use assets and lease liabilities on our consolidated balance sheet at January 1, 2019. The adoption of the New Lease Guidance did not have a material effect on our results of operations and had no impact on cash flows. Additionally, there was no cumulative adjustment to partners’ capital. Refer to Note 13 for the additional financial statement disclosures required by the New Lease Guidance.

3. Revenue from Contracts with Customers

Significant Accounting Policy

Revenue is measured based on consideration specified in a contract with a customer. The Partnership recognizes revenue when it satisfies a performance obligation by transferring control over goods and services to a customer.

Shipping and handling costs (e.g., the application of anti-freezing agents) are accounted for as fulfillment costs. The Partnership includes any fulfillment costs billed to customers as reductions to the corresponding expenses included in cost of coal produced and transportation expense.

Nature of Goods and Services

The Partnership’s primary source of revenue is from the sale of coal to domestic and international customers through short-term and long-term coal sales contracts. Coal sales revenue includes the sale to customers of coal produced and, from time to time, the re-sale of coal purchased from third-parties or from one of our affiliates. Performance obligations, consisting of individual tons of coal, are satisfied at a point in time when control is transferred to a customer.  For domestic coal sales, this generally occurs when coal is loaded onto railcars at the mine or onto barges at terminals.  For coal sales to international markets, this generally occurs when coal is loaded onto an ocean vessel.  

The Partnership’s coal sales contracts typically range in length from one to three years, however some agreements have terms of as little as one month. Coal sales contracts generally provide for either a fixed base price or a base price determined by a market index. The base price is subject to quality and weight adjustments. Quality and weight adjustments are recorded as necessary based on coal sales contract specifications as a reduction or increase to coal sales revenue. The coal sales contracts also may give the customer the option to vary volumes, subject to certain minimums. Coal sales are generally invoiced upon shipment and payment is due from customers within standard industry credit timeframes.  

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Contract Costs

The Partnership applies the practical expedient in ASC 340-40-25-4, whereby the Partnership recognizes the incremental costs of obtaining contracts as an expense when incurred if the amortization period of the assets that the Partnership would have recognized is one year or less. These costs are included in selling, general and administrative expenses.

Other Revenues

Other revenues consist primarily of a transport lease and overriding royalty agreements with Murray Energy (see Note 9). These arrangements are accounted for under guidance contained in ASC 310 Receivables, ASC 360 Property, Plant, and Equipment, and ASC 842 Leases and therefore are outside the scope of ASC 606.

4. Supplemental Cash Flow Information

The following is supplemental information to the condensed consolidated statement of cash flows:

5. Accounts Receivable

Accounts receivable consist of the following:

6. Inventories, Net

Inventories, net consist of the following:

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7. Property, Plant, Equipment and Development, Net

Property, plant, equipment and development, net consist of the following:

8. Long-Term Debt and Finance Lease Obligations

Long-term debt and finance lease obligations consist of the following:

Term Loan due 2022

The Term Loan due 2022 bears interest at the borrower’s option of (a) LIBOR (subject to a LIBOR floor of 1.00%) plus 5.75% per annum; or (b) a base rate plus 4.75% per annum. The Term Loan due 2022 also requires us to prepay outstanding borrowings (the “Excess Cash Flow Provisions”), subject to certain exceptions. The Excess Cash Flow Provisions are calculated annually and are payable 95 days after year-end.  During the nine months ended September 30, 2019, we prepaid $19.6 million of outstanding borrowings under the Excess Cash Flow Provisions for the annual period ended December 31, 2018.  

Second Lien Notes due 2023

The Second Lien Notes due 2023 have a maturity date of April 1, 2023 and bear interest at a rate of 11.50% per annum, payable in cash semi-annually on April 1 and October 1.

On October 1, 2019, the Issuers elected to exercise the grace period with respect to the interest payment due under the Indenture governing the Second Lien Notes due 2023. The election to exercise the grace period extended the time period the Issuers have to make the approximately $24.4 million interest payment without triggering an event of default under the Indenture.

On October 23, 2019, the Issuers sought the consent of the Holders of the Second Lien Notes due 2023 to amend (such amendments, the “Amendments”) the Indenture and sought the consent of the Holders to waive (such waiver, the “Waivers”) certain Defaults or Events of Defaults arising under the Indenture, in each case, as more fully described below.

As of October 30, 2019, the Issuers received consents to the Amendments from Holders of at least a majority in aggregate principal amount of the outstanding Second Lien Notes due 2023 not owned by the Issuers or their affiliates. As a result, on

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October 30, 2019, the Issuers, the guarantors party thereto and Wilmington Trust, National Association, the trustee for the

Second Lien Notes due 2023, entered into a supplemental indenture (the “Supplemental Indenture”) providing for the

Amendments to the Indenture.

The Amendments (i) amend Section 6.01(b) of the Indenture to extend the grace period for payment of interest due on the

Second Lien Notes due 2023 from 30 days to 90 days and (ii) amend Section 4.03(d) of the Indenture to exclude the fiscal period ended September 30, 2019 from the requirement that the Issuers hold a publicly accessible conference call to discuss the Issuers’ financial information for the relevant fiscal period.

As of October 30, 2019, Holders of at least a majority in aggregate principal amount of the outstanding Second Lien Notes due

2023 not owned by the Issuers or their affiliates also delivered Waivers that waived any Default or Event of Default, including under Section 6.01(b) of the Indenture, arising as a result of the Issuers’ failure to make the interest payment that was due to be paid by the Issuers on October 1, 2019. The Waivers did not waive any obligation of the Issuers to make such payment of interest, or the right of any Holder to receive such payment (including as contemplated by Section 6.07 of the Indenture).

Revolving Credit Facility

The Revolving Credit Facility has a total borrowing capacity of $170.0 million and bears interest at the borrower’s option of (a) LIBOR (subject to a floor of zero) plus an applicable margin ranging from 5.25% to 5.50% per annum or (b) a base rate plus an applicable margin ranging from 4.25% to 4.50% per annum. We are required to pay a quarterly commitment fee with respect to the unused portions of our Revolving Credit Facility and customary letter of credit fees.

As of September 30, 2019, there was $157.0 million in outstanding borrowings under the Revolving Credit Facility and $12.3 million of outstanding letters of credit secured by the Revolving Credit Facility. 

Liquidity, Capital Resources, Debt Obligations and Potential Going Concern Considerations

Refer to Note 1 for information and disclosures related to our liquidity, capital resources, debt obligations and potential going concern considerations.

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9. Related-Party Transactions

Overview

Affiliated entities of FELP principally include: (a) Murray Energy, owner of a 80% interest in our general partner, owner of all of the outstanding subordinated limited partner units, and owner of approximately 12% of the outstanding common limited partner units and (b) Foresight Reserves, its affiliates, and other entities owned and controlled by the estate of Chris Cline, the former majority owner and former chairman of our general partner. We routinely engage in transactions in the normal course of business with Murray Energy and its subsidiaries and Foresight Reserves and its affiliates. These transactions include, among others, production royalties, transportation services, administrative arrangements, coal handling and storage services, supply agreements, service agreements, land leases, land purchases, and sale-leaseback financing arrangements. We also acquire mining equipment from subsidiaries of Murray Energy.

Limited Partnership Agreement

FEGP manages the Partnership’s operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. Murray Energy and Foresight Reserves have the right to select the directors of the general partner. The members of the board of directors of the general partner are not elected by the unitholders and are not subject to reelection by the unitholders. The officers of the general partner manage the day-to-day affairs of the Partnership’s business. The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses incurred or payments made by the general partner on behalf of the Partnership. No amounts were incurred by the general partner or reimbursed under the partnership agreement from the IPO date to September 30, 2019.

Transactions with Murray Energy and Affiliates (including Javelin Global Commodities)

Murray Energy Management Services Agreement

In April 2015, a management services agreement (“MSA”) was executed between FEGP and Murray American Coal, Inc. (the ”Manager”), a wholly-owned subsidiary of Murray Energy, pursuant to which the Manager provided certain management and administration services to FELP for a quarterly fee of $3.5 million ($14.0 million on an annual basis), subject to contractual adjustments. To the extent that FELP or FEGP directly incurs costs for any services covered under the MSA, then the Manager’s quarterly fee is reduced accordingly. Also, to the extent that the Manager utilizes outside service providers to perform any of the services under the MSA, then the Manager is responsible for those outside service provider costs. The initial term of the MSA extends through December 31, 2022 and is subject to termination provisions. Upon the exercise of the FEGP Option, FEGP entered into an amended and restated MSA pursuant to which the quarterly fee for the Manager to provide certain management and administration services to FELP was increased to $5.0 million ($20.0 million on an annual basis) and is subject to future contractual escalations and adjustments (currently $5.2 million per quarter as of September 30, 2019).

Murray Energy Transport Lease and Overriding Royalty Agreements

In April 2015, American Century Transport LLC (“American Transport”), a subsidiary of the Partnership, entered into a purchase and sale agreement (the “PSA”) with American Energy Corporation (“American Energy”), a subsidiary of Murray Energy, pursuant to which American Energy sold to American Transport certain mining and transportation assets for $63.0 million. Concurrent with the PSA, American Transport entered into a lease agreement (the “Transport Lease”) with American Energy pursuant to which (i) American Transport leased to American Energy a tract of real property, two coal preparation plants and related coal handling facilities at American Energy’s Century Mine situated in Belmont and Monroe Counties, Ohio and (ii) American Transport receives from American Energy a fee ranging from $1.15 to $1.75 for every ton of coal mined, processed and/or transported using such assets, subject to a quarterly recoupable minimum fee of $1.7 million for an initial term of fifteen years. The Transport Lease is being accounted for as a direct financing lease.  The total remaining minimum payments under the Transport Lease was $72.7 million at September 30, 2019, with unearned income equal to $22.2 million. The unearned income is reflected as other revenue over the term of the lease using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned. As of September 30, 2019, the outstanding Transport Lease financing receivable was $50.5 million, of which $3.3 million was classified as current in the consolidated balance sheet.

Also, in April 2015, American Century Minerals LLC (“American Century Minerals”), a newly created subsidiary of the Partnership, entered into an overriding royalty agreement (“ORRA”) with Murray Energy subsidiaries’ American Energy and Consolidated Land Company (collectively, “AEC”), pursuant to which AEC granted to American Century Minerals an overriding royalty interest ranging from $0.30 to $0.50 for each ton of coal mined, removed and sold from certain coal reserves situated near the Century Mine in Belmont and Monroe Counties, Ohio for $12.0 million. The ORRA is subject to a minimum recoupable quarterly fee of $0.5 million and has an initial term of eighteen years. This overriding royalty was accounted for as a financing arrangement.  The total remaining minimum payments under the ORRA was $26.7 million at September 30, 2019, with unearned income equal to $15.6 million. The

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payments the Partnership receives with respect to the ORRA are reflected partially as a return of the initial investment (reduction in the affiliate financing receivable) and partially as other revenue over the life of the agreement using the effective interest method. Any amounts in excess of the contractual minimums are recorded as other revenue when earned.  As of September 30, 2019, the outstanding ORRA financing receivable was $11.1 million, of which $0.3 million was classified as current in the consolidated balance sheet.

Coals Sales and Purchases with Murray Energy and Affiliates

We sell coal to Javelin Global Commodities (“Javelin”), which is an international commodities marketing and trading joint venture owned by Murray Energy, Uniper (formerly E.ON Global Commodities SE), and management of Javelin. We incur sales and marketing expenses on export sales to Javelin.  In addition, we are responsible for transportation costs on certain export sales to Javelin.  

From time to time, we also purchase and sell coal to Murray Energy and its affiliates to, among other things, meet each of our customer contractual obligations.

Murray Energy Transportation Arrangements

Murray Energy may transport and transload coal under our transportation and transloading agreements with third-party rail, barge, and terminal companies, resulting in usage fees owed to the third-party companies by the Partnership.  These usage fees are billed to Murray Energy, resulting in no impact to our consolidated statements of operations. The usage of the railway lines, barges, and terminal facilities with these third-party companies by Murray Energy counts towards the minimum annual throughput volumes with these third-parties, thereby reducing the Partnership’s exposure to contractual liquidated damage charges.  There was $0.8 million of such usage fees during the three and nine months ended September 30, 2019.  There were no usage fees during the three and nine months ended September 30, 2018.

We have an arrangement with Murray Energy whereby we utilize capacity on a Murray Energy transloading contract with a third-party, thereby allowing Murray Energy to reduce its exposure to certain contractual liquidated damage charges. To compensate the Partnership for the reduced contractual liquidated damages, Murray Energy reimbursed the Partnership $0.0 million and $3.4 million for the three months ended September 30, 2019 and 2018, respectively, and $3.8 million and $8.0 million for the nine months ended September 30, 2019 and 2018, respectively. The amounts are included in transportation on the consolidated statements of operations.

We earn terminal revenues for Murray Energy’s occasional usage of our Sitran transloading facility.

Other Murray Energy Transactions

We regularly purchase equipment, supplies, rebuild, and other services from affiliates of Murray Energy. On occasion, our subsidiaries provide similar services to affiliates of Murray Energy.  We also enter into combined procurement transactions with Murray Energy to combine scale and increase purchasing leverage.  

From time to time, we may also reimburse Murray Energy for costs paid by them on our behalf, including certain insurance premiums.

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Transactions with Foresight Reserves and Affiliates

Mineral Reserve Leases

Our mines have a series of mineral reserve leases with Colt, LLC and Ruger, LLC (“Ruger”), subsidiaries of Foresight Reserves. Each of these leases have initial terms of 10 years with six renewal periods of five years each, at the election of the lessees, and generally require the lessees to pay the greater of $3.40 per ton or 8.0% of the gross sales price, as defined in the respective agreements, of such coal. We also have overriding royalty agreements with Ruger pursuant to which we pay royalties equal to 8.0% of the gross selling prices, as defined in the agreements. Each of these mineral reserve leases generally require a minimum annual royalty payment, which is recoupable only against actual production royalties from future tons mined during the period of ten years following the date on which any such royalty is paid.

Other Foresight Reserves Transactions

We are party to two surface leases in relation to the coal preparation plant and rail loadout facility at Williamson with New River Royalty, a subsidiary of Foresight Reserves. The primary terms of the leases expire on October 15, 2021, but may be extended by New River Royalty for additional five-year terms under the same terms and conditions until all of the merchantable and mineable coal has been mined and removed from Williamson. Williamson is required to pay aggregate rent of $100,000 per year to New River Royalty under the leases.

We are party to a surface lease at our Sitran terminal with New River Royalty. The annual lease amount is $50,000 and the primary term of the lease expires on December 31, 2020, but it may be extended at the election of Sitran for successive five year periods.

We are also party to various land easements and similar agreements with New River Royalty with varying terms and renewal options. Annual lease amounts on these arrangements are not significant individually or in aggregate.

In January 2019, we purchased two tracts of land from New River Royalty for total consideration of $6.1 million.

Reserves Investor Group

The Reserves Investor Group includes the estate of Christopher Cline, the Cline Resource and Development Company (“CRDC”), the four trusts established for the benefit of Mr. Cline’s children (the “Cline Trust”), and certain other limited liability companies owned or controlled by individuals with limited partner interests in Foresight Reserves through indirect ownership. Concurrent with and subsequent to certain refinancing transactions in March 2017, CRDC and the Cline Trust acquired investments in our Term Loan due 2022 and our Second Lien Notes due 2023 on consistent terms as the unaffiliated owners of these notes.

As of September 30, 2019, CRDC owned $9.9 million and $29.1 million of the outstanding principal on our Term Loan due 2022 and our Second Lien Notes due 2023, respectively.

As of September 30, 2019, the Cline Trust owned $9.9 million of the outstanding principal on our Term Loan due 2022. The Cline Trust is also a holder of 17,556 of FELP’s outstanding warrants as of September 30, 2019.

Beginning in 2019, we are party to an agreement with an affiliate of the Reserves Investor Group in which we receive royalties based on certain methane gas sales. Royalty revenues on this arrangement were not significant during the three and nine months ended September 30, 2019.  

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The following table summarizes certain affiliate amounts included in our condensed consolidated balance sheets:

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A summary of (income) expenses incurred with affiliated entities is as follows for the three and nine months ended September 30, 2019 and 2018:

Principal location in the condensed consolidated financial statements:

(1) – Coal sales

(2) – Other revenues

(3) – Cost of coal produced (excluding depreciation, depletion and amortization)

(4) – Transportation  

(5) – Cost of coal produced (excluding depreciation, depletion and amortization) and property, plant and equipment, net, as applicable

(6) – Cost of coal purchased  

(7) – Selling, general and administrative

(8) – Other operating (income) expense, net

10. Earnings per Limited Partner Unit

We compute earnings per unit (“EPU”) using the two-class method for master limited partnerships as prescribed in ASC 260, Earnings Per Share. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic EPU. In addition to the common and subordinated units, we have also identified the general partner interest and our incentive distribution rights (“IDR”) as participating securities. Under the two-class method, EPU is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The Partnership’s net loss is allocated to the limited partners, including the holders of the subordinated units, in accordance with the partnership agreement on their respective ownership percentages, after giving effect to any special income or expense allocations and incentive distributions paid to the general partner, if any. The holders of our IDRs have the right to receive increasing percentages of quarterly distributions from operating surplus after certain distribution levels defined in the partnership agreement have been achieved. The general partner has no obligation to make distributions; therefore, undistributed earnings of the Partnership are not allocated to the IDRs. Basic EPU is computed by dividing net earnings attributable to unitholders by the weighted-average number of units outstanding during each period. Diluted EPU reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units.

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The following table illustrates the Partnership’s calculation of net loss per common and subordinated unit for the three month periods indicated: