UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. 1
ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2015 or
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 1-31465
NATURAL RESOURCE PARTNERS L.P.
(Exact name of registrant as specified in its charter)
Delaware | 35-2164875 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | |
1201 Louisiana Street, Suite 3400, Houston, Texas 77002 (Address of principal executive offices) | ||
Registrant's telephone number, including area code (713) 751-7507
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
Common Units representing limited partnership interests | New York Stock Exchange | |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
¨ Large Accelerated Filer | x Accelerated Filer | ¨ Non-accelerated Filer | ¨ Smaller Reporting Company |
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2) Yes ¨ No ý
The aggregate market value of the common units held by non-affiliates of the registrant was approximately $295.0 million on June 30, 2015 based on a price of $37.90 per unit, which was the closing price of the common units as reported on the New York Stock Exchange (after giving effect to the one-for-ten reverse unit split effective on February 17, 2016).
As of March 1, 2016, there were 12.2 million common units outstanding. Documents incorporated by reference: None.
Explanatory Note
We are filing this Amendment No. 1 on Form 10-K/A solely to correct a typographical error in Ernst & Young LLP's independent registered public accountants’ report contained in Item 8. Financial Statements and Supplementary Data of our original Annual Report on Form 10-K filed on March 11, 2016 (the "Original Report"). There are no changes to the financial or supplemental information contained in Item 8.
The typographical error was an inadvertent reference to Natural Resource Partners L.P. in regards to the amounts based on the report of other auditors. The amounts of Ciner Wyoming LLC, a Limited Liability Company in which Natural Resource Partners L.P. owns a 49% interest, were audited by Deloitte & Touche LLP and should have been referenced accordingly.
In order to comply with certain technical requirements of the SEC’s rules in connection with the filing of this amendment on Form 10-K/A, we are including in this amendment the complete text of Item 8. We are also including in this amendment updated certifications of our principal executive and principal financial officers and updated consents of Ernst & Young LLP and Deloitte & Touche LLP.
This Amendment No. 1 on Form 10-K/A continues to speak as of the date of our Original Report, and we have not updated the disclosures contained in this Amendment No. 1 to reflect any events that occurred at a date subsequent to the filing of the Original Report.
i
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page | |
ii
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners of Natural Resource Partners L.P.
We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2015 and 2014, and the related consolidated statements of comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Ciner Wyoming LLC (Ciner Wyoming), a Limited Liability Company in which Natural Resource Partners L.P. owns a 49% interest. In the consolidated financial statements Natural Resource Partners L.P.’s investment in Ciner Wyoming is stated at $262 million and $264 million as of December 31, 2015 and 2014, respectively, and Natural Resource Partners L.P.'s equity in the net income of Ciner Wyoming is stated at $50 million, $41 million and $34 million for the three years in the period ended December 31, 2015, respectively. Those statements were audited by other auditors whose report has been furnished to us. Our opinion, insofar as it relates to the amounts included for Ciner Wyoming, is based on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Natural Resource Partners L.P. at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
The condensed consolidating balance sheets and statements of comprehensive income (loss) appearing in Note 17 of the consolidated financial statements have been subjected to audit procedures performed in conjunction with the audit of Natural Resource Partners L.P.’s consolidated financial statements. Such information is the responsibility of the Partnership’s management. Our audit procedures included determining whether the information reconciles to the financial statements or the underlying accounting and other records, as applicable, and performing procedures to test the completeness and accuracy of the information. In our opinion, the information is fairly stated, in all material respects, in relation to the financial statements as a whole.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 11, 2016, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
March 11, 2016
1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Managers and Members of
Ciner Wyoming LLC
Atlanta, Georgia
We have audited the accompanying balance sheets of Ciner Wyoming LLC (the "Company") as of December 31, 2015 and 2014 and the related statements of operations and comprehensive income, members’ equity, and cash flows for each of the three years in the period ended December 31, 2015, and the related notes to the financial statements. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Atlanta, Georgia
March 11, 2016
2
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31, 2015 | December 31, 2014 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 51,773 | $ | 50,076 | |||
Accounts receivable, net | 50,167 | 66,455 | |||||
Accounts receivable—affiliates | 6,864 | 9,494 | |||||
Inventory | 7,835 | 5,814 | |||||
Prepaid expenses and other | 4,490 | 4,279 | |||||
Total current assets | 121,129 | 136,118 | |||||
Land | 25,022 | 25,243 | |||||
Plant and equipment, net | 61,239 | 60,093 | |||||
Mineral rights, net | 1,094,027 | 1,781,852 | |||||
Intangible assets, net | 56,927 | 60,733 | |||||
Equity in unconsolidated investment | 261,942 | 264,020 | |||||
Long-term contracts receivable—affiliate | 47,359 | 50,008 | |||||
Goodwill | — | 52,012 | |||||
Other assets | 15,306 | 14,645 | |||||
Other assets—affiliate | 1,124 | — | |||||
Total assets | $ | 1,684,075 | $ | 2,444,724 | |||
LIABILITIES AND CAPITAL | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 8,465 | $ | 22,465 | |||
Accounts payable—affiliates | 1,464 | 950 | |||||
Accrued liabilities | 45,735 | 43,533 | |||||
Current portion of long-term debt, net | 80,983 | 80,983 | |||||
Total current liabilities | 136,647 | 147,931 | |||||
Deferred revenue | 80,812 | 73,207 | |||||
Deferred revenue—affiliates | 82,853 | 87,053 | |||||
Long-term debt, net | 1,284,083 | 1,374,336 | |||||
Long-term debt, net—affiliate | 19,930 | 19,904 | |||||
Other non-current liabilities | 6,808 | 22,138 | |||||
Commitments and contingencies (see Note 14) | |||||||
Partners’ capital: | |||||||
Common unitholders’ interest (12.2 million units outstanding) | 79,094 | 709,019 | |||||
General partner’s interest | (606 | ) | 12,245 | ||||
Accumulated other comprehensive loss | (2,152 | ) | (459 | ) | |||
Total partners’ capital | 76,336 | 720,805 | |||||
Non-controlling interest | (3,394 | ) | (650 | ) | |||
Total capital | 72,942 | 720,155 | |||||
Total liabilities and capital | $ | 1,684,075 | $ | 2,444,724 | |||
The accompanying notes are an integral part of these consolidated financial statements.
3
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands, except per unit data)
For the Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Revenues and other income: | |||||||||||
Coal, hard mineral royalty and other | $ | 156,638 | $ | 172,160 | $ | 213,825 | |||||
Coal, hard mineral royalty and other—affiliates | 89,715 | 84,559 | 93,026 | ||||||||
VantaCore | 139,013 | 42,051 | — | ||||||||
Oil and gas | 53,565 | 59,566 | 17,080 | ||||||||
Equity in earnings of Ciner Wyoming | 49,918 | 41,416 | 34,186 | ||||||||
Total revenues and other income | 488,849 | 399,752 | 358,117 | ||||||||
Operating expenses: | |||||||||||
Operating and maintenance expenses | 155,959 | 83,433 | 33,211 | ||||||||
Operating and maintenance expenses—affiliates, net | 16,031 | 10,770 | 8,821 | ||||||||
Depreciation, depletion and amortization | 100,828 | 79,876 | 64,377 | ||||||||
General and administrative | 7,036 | 7,287 | 11,452 | ||||||||
General and administrative—affiliates | 5,312 | 3,258 | 3,286 | ||||||||
Asset impairments | 681,594 | 26,209 | 734 | ||||||||
Total operating expenses | 966,760 | 210,833 | 121,881 | ||||||||
Income (loss) from operations | (477,911 | ) | 188,919 | 236,236 | |||||||
Other income (expense) | |||||||||||
Interest expense | (93,827 | ) | (80,185 | ) | (64,396 | ) | |||||
Interest income | 18 | 96 | 238 | ||||||||
Other expense, net | (93,809 | ) | (80,089 | ) | (64,158 | ) | |||||
Net income (loss) | $ | (571,720 | ) | $ | 108,830 | $ | 172,078 | ||||
Net income (loss) attributable to partners: | |||||||||||
Limited partners | (559,492 | ) | 106,653 | 168,636 | |||||||
General partner | (12,228 | ) | 2,177 | 3,442 | |||||||
Basic and diluted net income (loss) per common unit | $ | (45.75 | ) | $ | 9.42 | $ | 15.39 | ||||
Weighted average number of common units outstanding | 12,230 | 11,326 | 10,958 | ||||||||
Net income (loss) | $ | (571,720 | ) | $ | 108,830 | $ | 172,078 | ||||
Add: comprehensive income (loss) from unconsolidated investment and other | (1,693 | ) | (81 | ) | 65 | ||||||
Comprehensive income (loss) | $ | (573,413 | ) | $ | 108,749 | $ | 172,143 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Common Unitholders | General Partner | Accumulated Other Comprehensive Income (Loss) | Partners' Capital Excluding Non-Controlling Interest | Non-Controlling Interest | Total Capital | |||||||||||||||||||||
Units | Amounts | |||||||||||||||||||||||||
Balance at December 31, 2012 | 10,603 | $ | 605,019 | $ | 10,026 | $ | (443 | ) | $ | 614,602 | $ | 2,845 | $ | 617,447 | ||||||||||||
Issuance of common units | 378 | 75,000 | — | — | 75,000 | — | 75,000 | |||||||||||||||||||
Capital contribution | — | — | 1,531 | — | 1,531 | — | 1,531 | |||||||||||||||||||
Cost associated with equity transactions | — | (293 | ) | — | — | (293 | ) | — | (293 | ) | ||||||||||||||||
Distributions to unitholders | — | (241,588 | ) | (4,930 | ) | — | (246,518 | ) | — | (246,518 | ) | |||||||||||||||
Distributions to non-controlling interests | — | — | — | — | — | (2,521 | ) | (2,521 | ) | |||||||||||||||||
Net income | — | 168,636 | 3,442 | — | 172,078 | — | 172,078 | |||||||||||||||||||
Comprehensive income from unconsolidated investment and other | — | — | — | 65 | 65 | — | 65 | |||||||||||||||||||
Balance at December 31, 2013 | 10,981 | $ | 606,774 | $ | 10,069 | $ | (378 | ) | $ | 616,465 | $ | 324 | $ | 616,789 | ||||||||||||
Issuance of common units | 1,006 | 127,202 | — | — | 127,202 | — | 127,202 | |||||||||||||||||||
Issuance of common units for acquisitions | 243 | 31,604 | — | — | 31,604 | — | 31,604 | |||||||||||||||||||
Capital contribution | — | — | 3,240 | — | 3,240 | — | 3,240 | |||||||||||||||||||
Cost associated with equity transactions | — | (4,413 | ) | — | — | (4,413 | ) | — | (4,413 | ) | ||||||||||||||||
Distributions to unitholders | — | (158,801 | ) | (3,241 | ) | — | (162,042 | ) | — | (162,042 | ) | |||||||||||||||
Distributions to non-controlling interests | — | — | — | — | — | (974 | ) | (974 | ) | |||||||||||||||||
Net income | — | 106,653 | 2,177 | — | 108,830 | — | 108,830 | |||||||||||||||||||
Comprehensive loss from unconsolidated investment and other | — | — | — | (81 | ) | (81 | ) | — | (81 | ) | ||||||||||||||||
Balance at December 31, 2014 | 12,230 | $ | 709,019 | $ | 12,245 | $ | (459 | ) | $ | 720,805 | $ | (650 | ) | $ | 720,155 | |||||||||||
Cost associated with equity transactions | — | (109 | ) | — | — | (109 | ) | — | (109 | ) | ||||||||||||||||
Distributions to unitholders | — | (70,324 | ) | (1,434 | ) | — | (71,758 | ) | — | (71,758 | ) | |||||||||||||||
Distributions to non-controlling interests | — | — | — | — | — | (2,744 | ) | (2,744 | ) | |||||||||||||||||
Net loss | — | (559,492 | ) | (12,228 | ) | — | (571,720 | ) | — | (571,720 | ) | |||||||||||||||
Non-cash contributions | — | — | 811 | — | 811 | — | 811 | |||||||||||||||||||
Comprehensive loss from unconsolidated investment and other | — | — | — | (1,693 | ) | (1,693 | ) | — | (1,693 | ) | ||||||||||||||||
Balance at December 31, 2015 | 12,230 | $ | 79,094 | $ | (606 | ) | $ | (2,152 | ) | $ | 76,336 | $ | (3,394 | ) | $ | 72,942 | ||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
5
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Cash flows from operating activities: | |||||||||||
Net income (loss) | $ | (571,720 | ) | $ | 108,830 | $ | 172,078 | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
Asset impairment | 681,594 | 26,209 | 734 | ||||||||
Depreciation, depletion and amortization | 100,828 | 79,876 | 64,377 | ||||||||
Distributions from equity earnings from unconsolidated investments | 46,795 | 43,005 | 24,113 | ||||||||
Equity earnings from unconsolidated investment | (49,918 | ) | (41,416 | ) | (34,186 | ) | |||||
Gain on reserve swap | (9,290 | ) | (5,690 | ) | (8,149 | ) | |||||
Other, net | (1,295 | ) | 1,942 | (8,721 | ) | ||||||
Other, net—affiliates | (287 | ) | — | — | |||||||
Change in operating assets and liabilities: | |||||||||||
Accounts receivable | 16,486 | (8,685 | ) | 2,593 | |||||||
Accounts receivable—affiliates | 2,630 | (1,828 | ) | 2,947 | |||||||
Accounts payable | (3,775 | ) | (2,408 | ) | 1,633 | ||||||
Accounts payable—affiliates | 514 | 559 | (566 | ) | |||||||
Accrued liabilities | (4,676 | ) | (1,821 | ) | 7,927 | ||||||
Deferred revenue | 7,605 | 2,056 | 4,164 | ||||||||
Deferred revenue—affiliates | (4,200 | ) | 15,618 | 15,076 | |||||||
Accrued incentive plan expenses | (7,023 | ) | (5,265 | ) | 2,284 | ||||||
Other items, net | (1,030 | ) | (47 | ) | (516 | ) | |||||
Other items, net—affiliates | 186 | (180 | ) | 1,286 | |||||||
Net cash provided by operating activities | 203,424 | 210,755 | 247,074 | ||||||||
Cash flows from investing activities: | |||||||||||
Acquisition of mineral rights | (40,679 | ) | (356,026 | ) | (72,000 | ) | |||||
Acquisition of plant and equipment and other | (10,175 | ) | (2,454 | ) | — | ||||||
Proceeds from sale of plant and equipment and other | 11,024 | 1,006 | — | ||||||||
Proceeds from sale of mineral rights | 7,096 | 412 | 10,929 | ||||||||
Acquisition of equity interests | — | — | (293,085 | ) | |||||||
Acquisition of aggregates business | — | (168,978 | ) | — | |||||||
Return of equity and other unconsolidated investments | — | 3,633 | 48,833 | ||||||||
Return of long-term contract receivables—affiliate | 2,463 | 1,904 | 2,558 | ||||||||
Net cash used in investing activities | (30,271 | ) | (520,503 | ) | (302,765 | ) | |||||
Cash flows from financing activities: | |||||||||||
Proceeds from loans | 100,000 | 617,471 | 567,020 | ||||||||
Proceeds from loans—affiliate | — | 19,904 | — | ||||||||
Proceeds from issuance of common units | — | 127,202 | 75,000 | ||||||||
Capital contribution by general partner | — | 3,240 | 1,531 | ||||||||
Repayments of loans | (190,983 | ) | (327,983 | ) | (386,230 | ) | |||||
Distributions to partners | (71,758 | ) | (162,042 | ) | (246,518 | ) | |||||
Distributions to non-controlling interest | (2,744 | ) | (974 | ) | (2,521 | ) | |||||
Debt issue costs and other | (5,971 | ) | (9,507 | ) | (9,502 | ) | |||||
Net cash provided by (used in) financing activities | (171,456 | ) | 267,311 | (1,220 | ) | ||||||
Net increase (decrease) in cash and cash equivalents | 1,697 | (42,437 | ) | (56,911 | ) | ||||||
Cash and cash equivalents at beginning of period | 50,076 | 92,513 | 149,424 | ||||||||
Cash and cash equivalents at end of period | $ | 51,773 | $ | 50,076 | $ | 92,513 | |||||
Supplemental cash flow information: | |||||||||||
Cash paid during the period for interest | $ | 88,493 | $ | 76,155 | $ | 55,191 | |||||
Non-cash investing activities: | |||||||||||
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities | $ | 5,949 | $ | 11,879 | $ | 3,019 | |||||
Units issued for acquisition of aggregate operations | — | 31,604 | — | ||||||||
Non-cash contingent consideration on equity investments | — | — | 15,000 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
6
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Natural Resource Partners L.P. (the "Partnership"), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP ("NRP GP"), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning, operating, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, oil and gas, construction aggregates, frac sand and other natural resources. As used in these Notes to Consolidated Financial Statements, the terms "NRP," "we," "us" and "our" refer to Natural Resource Partners L.P. and its subsidiaries, unless otherwise stated or indicated by context.
The Partnership’s coal reserves are located in the three major U.S. coal-producing regions: Appalachia, the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. The Partnership does not operate any coal mines, but leases its coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine and sell its reserves in exchange for royalty payments. The Partnership also owns and manages infrastructure assets that generate additional revenues, primarily in the Illinois Basin.
The Partnership owns or leases aggregates and industrial minerals located in a number of states across the country. The Partnership derives a small percentage of its aggregates and industrial mineral revenues by leasing its owned reserves to third party operators who mine and sell the reserves in exchange for royalty payments. However, the majority of the Partnership’s aggregates revenues come through its ownership of VantaCore Partners LLC ("VantaCore"), which was acquired in October 2014. VantaCore specializes in the construction materials industry and operates four hard rock quarries, six sand and gravel plants, two asphalt plants and two marine terminals. VantaCore’s current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
The Partnership owns a 49% non-controlling equity interest in Ciner Wyoming LLC ("Ciner Wyoming"), a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, the Partnership’s operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. The Partnership receives regular quarterly distributions from this business, and records income in accordance with the equity method of accounting.
The Partnership also owns various interests in oil and gas properties that are located in the Williston Basin, the Appalachian Basin, Louisiana and Oklahoma. The Partnership’s interests in the Appalachian Basin, Louisiana and Oklahoma are minerals and royalty interests, while in the Williston Basin the Partnership owns non-operated working interests.
The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership owns its subsidiaries through two wholly owned operating companies: NRP (Operating) LLC ("NRP Opco") and NRP Oil and Gas LLC ("NRP Oil and Gas"). NRP Oil and Gas holds the Partnership's non operated oil and gas working interests in the Williston Basin. All other operations of the Partnership, including other oil and gas assets, are held by NRP Opco. NRP GP has sole responsibility for conducting the Partnership's business and for managing its operations. Because NRP GP is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Mr. Robertson is entitled to nominate all ten of the directors to the board of directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals, LLC, an affiliate of Christopher Cline.
2. 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
7
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 4.0x through March 31, 2016. Commencing with respect to the period ended June 30, 2016, the maximum leverage ratio reduces to 3.75x and reduces again to 3.5x 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 3.5x 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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 |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
3. Segment Information
The Partnership's segments are strategic business units that offer products and services to different customer segments in different geographies within the U.S. and that are managed accordingly. NRP has the following four operating segments:
Coal, Hard Mineral Royalty and Other—consists primarily of coal royalty, coal related transportation and processing assets, aggregate and industrial minerals royalty assets and timber. Our coal reserves are primarily located in Appalachia, the Illinois Basin and the Western United States. Our aggregates and industrial minerals are located in a number of states across the United States.
Soda Ash—consists of the Partnership's 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, our operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. We receive regular quarterly distributions from this business.
VantaCore—consists of our construction materials business acquired in October 2014 that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
Oil and Gas—consists of our non-operated working interests, royalty interests and overriding royalty interests in oil and natural gas properties. Our primary interests in oil and natural gas producing properties are non-operated working interests located in the Williston Basin in North Dakota and Montana. We also own fee mineral, royalty or overriding royalty interests in oil and gas properties in several other regions, including the Appalachian Basin, Oklahoma and Louisiana.
Direct segment costs and certain costs incurred at a corporate level that are identifiable and that benefit the Partnership's segments are allocated to the operating segments. These allocated costs include costs of: taxes, legal, information technology and shared facilities services and are included in Operating and maintenance expenses and Operating and maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income. Prior year general and administrative charges that are allocated to the operating segments have been reclassified to operating and maintenance expenses. Intersegment sales are at prices that approximate market.
In reconciling items to consolidated operating income, Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include corporate headquarters and overhead, financing, centralized treasury and accounting and other corporate-level activity not specifically allocated to a segment.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table summarizes certain financial information for each of the Partnership's operating segments (in thousands):
Operating Segments | ||||||||||||||||||||||||
For the Year Ended | Coal, Hard Mineral Royalty and Other | Soda Ash | VantaCore | Oil and Gas | Corporate and Financing | Total | ||||||||||||||||||
December 31, 2015 | ||||||||||||||||||||||||
Revenues (including affiliates) | $ | 246,353 | $ | 49,918 | $ | 139,013 | $ | 53,565 | $ | — | $ | 488,849 | ||||||||||||
Intersegment revenues (expenses) | 21 | — | (21 | ) | — | — | — | |||||||||||||||||
Depreciation, depletion and amortization | 44,478 | — | 15,578 | 40,772 | — | 100,828 | ||||||||||||||||||
Asset impairment | 307,800 | — | 6,218 | 367,576 | — | 681,594 | ||||||||||||||||||
Interest expense, net | — | — | — | — | (93,809 | ) | (93,809 | ) | ||||||||||||||||
Net income (loss) | (138,388 | ) | 49,918 | 272 | (377,365 | ) | (106,157 | ) | (571,720 | ) | ||||||||||||||
Capital expenditures | 428 | — | 14,039 | 30,457 | — | 44,924 | ||||||||||||||||||
Total assets at December 31, 2015 | 1,047,922 | 261,942 | 200,348 | 158,862 | 15,001 | 1,684,075 | ||||||||||||||||||
December 31, 2014 | ||||||||||||||||||||||||
Revenues (including affiliates) | $ | 256,719 | $ | 41,416 | $ | 42,051 | $ | 59,566 | $ | — | $ | 399,752 | ||||||||||||
Depreciation, depletion and amortization | 52,645 | — | 3,296 | 23,935 | — | 79,876 | ||||||||||||||||||
Asset impairment | 26,209 | — | — | — | — | 26,209 | ||||||||||||||||||
Interest expense, net | — | — | — | — | (80,089 | ) | (80,089 | ) | ||||||||||||||||
Net income (loss) | 143,678 | 41,416 | 32 | 14,338 | (90,634 | ) | 108,830 | |||||||||||||||||
Capital expenditures | 5,351 | — | 171,116 | 359,851 | — | 536,318 | ||||||||||||||||||
Total assets at December 31, 2014 | 1,403,762 | 264,020 | 219,658 | 540,713 | 16,571 | 2,444,724 | ||||||||||||||||||
December 31, 2013 | ||||||||||||||||||||||||
Revenues (including affiliates) | $ | 306,851 | $ | 34,186 | $ | — | $ | 17,080 | $ | — | $ | 358,117 | ||||||||||||
Depreciation, depletion and amortization | 58,502 | — | — | 5,875 | — | 64,377 | ||||||||||||||||||
Asset impairment | 734 | — | — | — | — | 734 | ||||||||||||||||||
Interest expense, net | — | — | — | — | (64,158 | ) | (64,158 | ) | ||||||||||||||||
Net income (loss) | 211,590 | 34,186 | — | 5,198 | (78,896 | ) | 172,078 | |||||||||||||||||
Capital expenditures | — | 293,085 | — | 75,019 | — | 368,104 | ||||||||||||||||||
Total assets at December 31, 2013 | 1,520,428 | 269,338 | — | 189,211 | 12,879 | 1,991,856 | ||||||||||||||||||
4. Acquisitions
VantaCore Acquisition
On October 1, 2014, the Partnership continued its effort to own a more diversified portfolio of natural resources by completing its acquisition of VantaCore for $200.6 million in cash and common units. At the time of acquisition, VantaCore operated three hard rock quarries, six sand and gravel plants, two asphalt plants, one underground limestone mine and one marine terminal. VantaCore is headquartered in Philadelphia, Pennsylvania and its current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. This acquisition aligned the Partnership’s effort to own a more diversified portfolio of natural resources.
The Partnership accounted for the transaction as a business combination under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
the acquisitions were expensed as incurred. The fair value of these assets and liabilities was estimated using a discounted cash flow technique with significant inputs including future production volumes, aggregate sales prices, reserves and operating costs that are not observable in the market and thus represents a Level 3 fair value measurement. The results of operations of the acquisition have been included in our consolidated financial statements since the acquisition date.
In the first quarter 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for various items of VantaCore’s plant and equipment that existed as of acquisition date. As a result of this adjustment, plant and equipment was increased by $22.5 million with a corresponding decrease to goodwill. In the second quarter 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for VantaCore’s right to mine and intangible assets that existed as of the acquisition date. As a result of this adjustment, Mineral rights, net and Intangible assets, net were increased by $24.7 million with a corresponding decrease to Goodwill. The purchase price allocation was further adjusted as more detailed analysis was completed for VantaCore’s asset retirement obligations that existed as of acquisition date. As a result of this adjustment, asset retirement obligations were decreased by $2.3 million with a corresponding decrease to the asset retirement cost that was capitalized as part of the related land, property and equipment. The accounting for the VantaCore acquisition was completed in the second quarter of 2015 with the exception of this asset retirement obligation adjustment that was recoded in the fourth quarter of 2015. Measurement-period adjustments were not material to prior period financial statements and were recorded during the period in which the amount of the adjustment was determined. The accounting for the VantaCore acquisition is summarized as follows (in thousands):
October 1, 2014 | |||
Consideration | |||
Cash | $ | 168,978 | |
NRP common units | 31,604 | ||
Total consideration given | $ | 200,582 | |
Allocation of Purchase Price | |||
Current assets | $ | 37,222 | |
Land, property and equipment | 59,946 | ||
Mineral rights | 111,500 | ||
Other assets | 4,347 | ||
Current liabilities | (16,953 | ) | |
Asset retirement obligation | (1,005 | ) | |
Goodwill | 5,525 | ||
Fair value of net assets acquired | $ | 200,582 | |
Included in the Consolidated Statements of Comprehensive Income was revenue of $42.1 million and operating income of $0.1 million for the year ended December 31, 2014. Transaction costs through December 31, 2014 associated with this acquisition were $2.9 million and were expensed as incurred. These expenses are reflected in Operating and maintenance expenses on the Consolidated Statements of Comprehensive Income.
Sanish Field Acquisition
On November 12, 2014, the Partnership continued its effort to own a more diversified portfolio of natural resources by completing its acquisition of non-operated oil and gas working interests in the Sanish Field of the Williston Basin from an affiliate of Kaiser-Francis Oil Company for $339.1 million.
The Partnership accounted for the transaction as a business combination under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with the acquisitions were expensed as incurred. The fair value of these assets and liabilities was estimated using a discounted cash flow technique with significant inputs that are not observable in the market and thus represents a Level 3 fair value measurement. Significant inputs used to determine the fair value include estimates of: (i) reserves, including estimated oil and natural gas reserves and risk-adjusted probable reserves; (ii) future commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The results of operations of the acquisition have been included in our consolidated financial statements since the acquisition date. The accounting for the Sanish Field acquisition was completed in the second quarter of 2015 without significant changes during the measurement period and is summarized as follows (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
November 12, 2014 | |||
Consideration | |||
Cash | $ | 339,093 | |
Allocation of Purchase Price | |||
Mineral rights - proven oil and gas properties | 298,293 | ||
Mineral rights - probable and possible oil and gas resources | 40,800 | ||
Fair value of net assets acquired | $ | 339,093 | |
Included in the Consolidated Statements of Comprehensive Income was revenue of $12.8 million and operating income of $3.7 million for the year ended December 31, 2014. The transaction costs incurred in connection with this acquisition were $1.8 million through December 31, 2014, and were expensed as incurred. These expenses are reflected in Operating and maintenance expenses on the Consolidated Statements of Comprehensive Income.
Pro Forma Financial Information (unaudited)
The following unaudited pro forma financial information (in thousands) presents a summary of the Partnership’s consolidated revenues, net income and net income per common unit for the twelve months ended December 31, 2014 and 2013 assuming the VantaCore and Sanish Field acquisitions had been completed as of January 1, 2013, including adjustments to reflect the values assigned to the net assets acquired:
For the Years ended December 31, | |||||||
2014 | 2013 | ||||||
Total revenues and other income | $ | 533,517 | $ | 579,933 | |||
Net income | $ | 122,319 | $ | 197,164 | |||
Basic and diluted net income per common unit | $ | 9.90 | $ | 16.00 | |||
Other Oil and Gas Aquisitions
During the year ended December 31, 2013, the Partnership also completed two smaller acquisitions of oil and natural gas properties located in the Williston Basin as described below:
Sundance Acquisition
In December, 2013, the Partnership completed the acquisition of non-operated working interests in oil and gas properties in the Williston Basin of North Dakota from Sundance Energy, Inc. for $29.4 million, following post-closing purchase price adjustments. The Partnership accounted for the transaction in accordance with the authoritative guidance for business combinations. During the third quarter of 2014, the Partnership finalized the determination of the fair value of the assets acquired and liabilities assumed in the acquisition, with no material adjustments. The assets acquired are included in Mineral rights in the accompanying Consolidated Balance Sheets.
Abraxas Acquisition
In August, 2013, the Partnership completed the acquisition of non-operated working interests in oil and gas properties in the Williston Basin of North Dakota and Montana from Abraxas Petroleum for $38.0 million, following post-closing purchase price adjustments. The Partnership accounted for the transaction in accordance with the authoritative guidance for business combinations. During the second quarter of 2014, the Partnership finalized the determination of the fair values of the assets acquired and liabilities assumed in the acquisition, with no material adjustments. The assets acquired are included in Mineral rights on the accompanying Consolidated Balance Sheets.
With respect to the Abraxas and Sundance acquisitions, revenues of $5.4 million and operating income of $2.5 million were included in the Consolidated Statements of Comprehensive Income and Consolidated Balance Sheet for the year ended December 31, 2013.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
5. Equity Investment
We account for our 49% investment in Ciner Wyoming LLC ("Ciner Wyoming", and formerly "OCI Wyoming LLC") using the equity method of accounting. Ciner Wyoming distributed $46.8 million, $46.6 million and $72.9 million to us in the year ended December 31, 2015, 2014 and 2013, respectively.
The difference between the amount at which the investment in Ciner Wyoming is carried and the amount of underlying equity in Ciner Wyoming's net assets was $154.8 million and $162.7 million as of December 31, 2015 and 2014, respectively. This excess basis relates to plant, property and equipment and right to mine assets. The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over a weighted average of 28 years. The excess basis difference that relates to right to mine assets is being amortized into income using the units of production method.
Our equity in the earnings of Ciner Wyoming is summarized as follows (in thousands):
For the Year Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Income allocation to NRP’s equity interests | $ | 54,709 | $ | 47,354 | $ | 37,036 | |||||
Amortization of basis difference | (4,791 | ) | (5,938 | ) | (2,850 | ) | |||||
Equity in earnings of unconsolidated investment | $ | 49,918 | $ | 41,416 | $ | 34,186 | |||||
The results of Ciner Wyoming’s operations are summarized as follows (in thousands):
For the Year Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Sales | $ | 486,393 | $ | 465,032 | $ | 442,132 | |||||
Gross profit | 131,493 | 118,439 | 94,299 | ||||||||
Net Income | 111,650 | 96,640 | 79,655 | ||||||||
The financial position of Ciner Wyoming is summarized as follows (in thousands):
For the Year Ended December 31, | |||||||
2015 | 2014 | ||||||
Current assets | $ | 144,695 | $ | 179,851 | |||
Noncurrent assets | 233,845 | 223,053 | |||||
Current liabilities | 43,018 | 47,704 | |||||
Noncurrent liabilities | 116,808 | 149,192 | |||||
6. Inventory
The components of inventories at December 31, 2015 and 2014 are as follows (in thousands):
December 31, 2015 | December 31, 2014 | ||||||
Aggregates | $ | 7,056 | $ | 4,596 | |||
Supplies and parts | 779 | 1,218 | |||||
Total inventory | $ | 7,835 | $ | 5,814 | |||
7. Plant and Equipment
The Partnership’s plant and equipment consist of the following (in thousands):
December 31, 2015 | December 31, 2014 | ||||||
Plant and equipment at cost | $ | 92,203 | $ | 89,759 | |||
Construction in process | 1,074 | 457 | |||||
Less accumulated depreciation | (32,038 | ) | (30,123 | ) | |||
Total plant and equipment, net | $ | 61,239 | $ | 60,093 | |||
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Depreciation expense related to the Partnership's plant and equipment totaled $15.9 million, $7.6 million and $6.0 million for the year ended December 31, 2015, 2014 and 2013, respectively. During the second quarter of 2015 the Partnership recorded a $2.3 million impairment expense related to a coal preparation plant and during the fourth quarter of 2015 the Partnership recorded a $4.7 million impairment expense related to coal processing and transportation assets as well as obsolete equipment at our Logan office. The fair value measurement of these impaired assets recorded at fair value were $0.0 million at the end of the reporting period. The Partnership also recorded a $0.7 million impairment expense related to obsolete plant and equipment at VantaCore. During the fourth quarter of 2014, the Partnership recorded $0.8 million in impairment expense related to a coal preparation plant. These impairment charges are included in Asset impairments in the Consolidated Statements of Comprehensive Income for the year ending December 31, 2015 and December 31, 2014, respectively.
8. Mineral Rights
The Partnership’s mineral rights consist of the following (in thousands):
For the Year Ended December 31, 2015 | |||||||||||
Carrying Value | Accumulated Depletion | Net Book Value | |||||||||
Coal, Hard Mineral Royalty and Other | $ | 1,278,274 | $ | (432,260 | ) | $ | 846,014 | ||||
VantaCore | 112,700 | (3,082 | ) | 109,618 | |||||||
Oil and Gas | 155,293 | (16,898 | ) | 138,395 | |||||||
Total | $ | 1,546,267 | $ | (452,240 | ) | $ | 1,094,027 | ||||
For the Year Ended December 31, 2014 | |||||||||||
Carrying Value | Accumulated Depletion | Net Book Value | |||||||||
Coal, Hard Mineral Royalty and Other | $ | 1,680,169 | $ | (505,582 | ) | $ | 1,174,587 | ||||
VantaCore | 87,907 | (482 | ) | 87,425 | |||||||
Oil and Gas | 560,395 | (40,555 | ) | 519,840 | |||||||
Total | $ | 2,328,471 | $ | (546,619 | ) | $ | 1,781,852 | ||||
Depletion expense related to the Partnership’s mineral rights totaled $80.3 million, $68.6 million and $54.6 million for the year ended December 31, 2015, 2014 and 2013, respectively.
Impairment of Mineral Rights
The Partnership has developed procedures to periodically evaluate its long-lived assets for possible impairment. These procedures are performed throughout the year and consider both quantitative and qualitative information based on historic, current and future performance and are designed to identify impairment indicators. If an impairment indicator is identified, 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 primarily 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. The inputs used by management for fair value measurements include significant inputs that are not observable in the market and thus represent a Level 3 fair value measurement for these types of assets. 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 that a separate impairment evaluation be completed on a significant property.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
During the years ended December 31, 2015, 2014 and 2013, the Partnership identified facts and circumstances that indicated that the carrying value of certain of its mineral rights exceed future cash flows from those assets and recorded non-cash impairment expense as follows (in thousands):
For the years ended December 31, | |||||||||||||||
Impaired Asset Description | 2015 | 2014 | 2013 | ||||||||||||
Oil and gas properties | $ | 367,576 | (1 | ) | $ | — | $ | — | |||||||
Coal properties | 257,468 | (2 | ) | 16,793 | (4 | ) | 734 | ||||||||
Hard mineral royalty properties | 43,402 | (3 | ) | 3,013 | (4 | ) | |||||||||
Total | $ | 668,446 | $ | 19,806 | $ | 734 | |||||||||
(1) | We recorded $335.7 million of oil and gas property impairment during the third quarter 2015 and $31.9 million during the fourth quarter of 2015. The fair value measurement of these impaired assets recorded at fair value were $108.0 million at the end of the reporting period. These impairments primarily resulted from declines in future expected realized commodity prices and reduced expected drilling activity on our acreage. NRP compared net capitalized costs of its oil and natural gas properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future net cash flows, NRP recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow method was used to estimate fair value. Significant inputs used to determine the fair value include estimates of: (i) oil and natural gas reserves and risk-adjusted probable and possible reserves; (ii) future commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The underlying commodity prices embedded in the Partnership's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing as of the measurement date, adjusted for estimated location and quality differentials. |
(2) | We recorded $1.5 million of coal property impairment during the second quarter of 2015, $247.8 million of coal property impairment during the third quarter of 2015 and $8.2 million during the fourth quarter of 2015. The fair value measurement of these impaired assets recorded at fair value were $0.4 million at the end of the reporting period. These impairments primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry. NRP compared net capitalized costs of its coal properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future cash flows, NRP recorded an impairment for the excess of net capitalized cost over fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. |
(3) | We recorded $43.4 million of aggregates property impairment during the third quarter of 2015. The fair value measurement of these impaired assets recorded at fair value was $0.0 million at the end of the reporting period. This impairment primarily resulted from greenfield development projects that have not performed as projected, leading to recent lease concessions on minimums and royalties combined with the continued regional market decline for certain properties. NRP compared net capitalized costs of its aggregates properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted cash flows, NRP recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. |
(4) | We recorded $16.8 million of coal property impairment and $3.0 million impairment of our aggregates properties during the fourth quarter of 2014. Management concluded certain unleased properties were impaired due primarily to the ongoing regulatory environment and continued depressed coal markets with little indications of improvement in the near term. The fair values for those unleased properties were determined for the associated reserves using Level 2 market approaches based upon recent comparable sales and Level 3 expected cash flows. |
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
9. Goodwill and Intangible Assets
The Partnership's intangible assets consist of the following (in thousands):
December 31, 2015 | December 31, 2014 | ||||||
Contract intangibles | $ | 81,109 | $ | 82,972 | |||
Other intangibles | 5,076 | 3,004 | |||||
Less accumulated amortization | (29,258 | ) | (25,243 | ) | |||
Total intangible assets, net | $ | 56,927 | $ | 60,733 | |||
Amortization expense related to the Partnership's intangible assets totaled $4.6 million, $3.6 million and $3.8 million for the years ended December 31, 2015, 2014 and 2013, respectively.
During the second quarter of 2014, the Partnership and a lessee amended an aggregates lease in its Coal, Hard Mineral Royalty and Other segment, which led the Partnership to conclude an impairment triggering event had occurred. Fair value of the lease agreement was determined using Level 3 expected cash flows. The resulting impairment expense of $5.6 million is included in Asset impairments on the Consolidated Statements of Comprehensive Income.
The estimates of amortization expense for the periods as indicated below are based on current mining plans and are subject to revision as those plans change in future periods.
For the Year Ended December 31, | Estimated Amortization Expense | |||
(in thousands) | ||||
2016 | $ | 3,544 | ||
2017 | 3,095 | |||
2018 | 3,108 | |||
2019 | 3,108 | |||
2020 | 3,108 | |||
The weighted average remaining amortization period for contract intangibles and other intangibles was 14 years and 31 years, respectively.
During the fourth quarter of 2014, $52.0 million of goodwill was added relating to the VantaCore acquisition. This amount represented the preliminary residual value. During 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for VantaCore’s property, plant and equipment, right to mine assets and asset retirement obligations that existed as of the acquisition date. These adjustments decreased goodwill by $46.5 million and resulted in an acquisition date goodwill of $5.5 million.
During the fourth quarter of 2015, we evaluated goodwill for impairment and compared the estimated fair value of the VantaCore reporting unit to its carrying amount. The carrying amount exceeded fair value and we recorded a $5.5 million goodwill impairment expense. The lower fair value was primarily a result of the deterioration in certain regional markets in which VantaCore operates causing a decline in future performance levels compared to levels estimated during the purchase price allocation process. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. These estimates were based on current conditions and historical experience applied to develop projections of future operating performance.
10. Debt and Debt—Affiliate
As used in this Note 10, references to "NRP LP" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC, or NRP Oil and Gas LLC, wholly owned subsidiaries of NRP LP, or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP LP. NRP Finance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP LP and a co-issuer with NRP LP on the 9.125% senior notes described below. See discussion of Management's Forecast, Strategic Plan and Going Concern Analysis and certain matters involving the Partnership's debt in Note 2.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
As of December 31, 2015 and 2014, Debt and debt—affiliate consisted of the following (in thousands):
December 31, 2015 | December 31, 2014 | ||||||
NRP LP Debt: | |||||||
$425 million 9.125% senior notes, with semi-annual interest payments in April and October, due October 2018, $300 million issued at 99.007% and $125 million issued at 99.5% | $ | 422,923 | $ | 422,167 | |||
Opco Debt: | |||||||
$300 million floating rate revolving credit facility, due October 2017 | 290,000 | — | |||||
$300 million floating rate revolving credit facility, due August 2016 | — | 200,000 | |||||
$200 million floating rate term loan, due January 2016 | — | 75,000 | |||||
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018 | 13,850 | 18,467 | |||||
8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019 | 85,714 | 107,143 | |||||
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020 | 38,462 | 46,154 | |||||
5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021 | 1,153 | 1,345 | |||||
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023 | 21,600 | 24,300 | |||||
4.73% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023 | 60,000 | 67,500 | |||||
5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 | 135,000 | 150,000 | |||||
8.92% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024 | 40,909 | 45,455 | |||||
5.03% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 | 148,077 | 161,538 | |||||
5.18% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026 | 42,308 | 46,154 | |||||
NRP Oil and Gas Debt: | |||||||
Reserve-based revolving credit facility due November 2019 | 85,000 | 110,000 | |||||
Total debt and debt—affiliate | 1,384,996 | 1,475,223 | |||||
Less: current portion of long-term debt, net | (80,983 | ) | (80,983 | ) | |||
Total long-term debt and debt—affiliate | $ | 1,304,013 | $ | 1,394,240 | |||
NRP LP Debt
Senior Notes
In September 2013, NRP LP, together with NRP Finance as co-issuer, issued $300.0 million of 9.125% Senior Notes due 2018 at an offering price of 99.007% of par. Net proceeds after expenses from the issuance of the senior notes were approximately $289.0 million. The senior notes call for semi-annual interest payments on April 1 and October 1 of each year, and will mature on October 1, 2018.
In October 2014, NRP LP, together with NRP Finance as co-issuer, issued an additional $125.0 million of its 9.125% Senior Notes due 2018 at an offering price of 99.5% of par. The notes constitute the same series of securities as the existing $300.0 million 9.125% senior notes due 2018 issued in September 2013. Net proceeds of $122.6 million from the additional issuance of the Senior Notes were used to fund a portion of the purchase price of NRP’s acquisition of non-operated working interests in oil and gas assets located in the Williston Basin in North Dakota. The notes call for semi-annual interest payments on April 1 and October 1 of each year and will mature on October 1, 2018.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
NRP and NRP Finance have the option to redeem the NRP Senior Notes, in whole or in part, at any time on or after April 1, 2016, at fixed redemption prices specified in the indenture governing the NRP Senior Notes (the "NRP Senior Notes Indenture"). Before April 1, 2016, NRP and NRP Finance may redeem all or part of the NRP Senior Notes at a redemption price equal to the sum of the principal plus a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Furthermore, before April 1, 2016, NRP and NRP Finance may on any one or more occasions redeem up to 35% of the aggregate principal amount of the notes with the net proceeds of certain public or private equity offerings at a redemption price of 109.125% of the principal amount of notes, plus any accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the notes issued under the indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In the event of a change of control, as defined in the indenture, the holders of the notes may require NRP and NRP Finance to purchase their notes at a purchase price equal to 101% of the principal amount of the notes, plus accrued and unpaid interest, if any.
The indenture governing the $425.0 million of senior notes issued by NRP LP (the "Indenture") contains covenants that, among other things, limit the ability of NRP LP and certain of its subsidiaries to incur or guarantee additional indebtedness. Under the Indenture, NRP LP and certain of its subsidiaries generally are not permitted to incur additional indebtedness unless, on a consolidated basis, the fixed charge coverage ratio (as defined in the indenture) is at least 2.0 to 1.0 for the four preceding full fiscal quarters. The ability of NRP LP and certain of its subsidiaries to incur additional indebtedness is further limited in the event the amount of indebtedness of NRP LP and certain of its subsidiaries that is senior to NRP LP’s unsecured indebtedness exceeds certain thresholds. As of December 31, 2015 and December 31, 2014, NRP was in compliance with the terms of the financial covenants contained in its debt agreements.
Opco Debt
All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries other than NRP Trona LLC, as further described below. As of December 31, 2015 and December 31, 2014, Opco was in compliance with the terms of the financial covenants contained in its debt agreements.
Revolving Credit Facility
In June 2015, Opco entered into a $300.0 million Third Amended and Restated Credit Agreement (the "A&R Revolving Credit Facility"), which amended and restated Opco’s $300.0 million Second Amended and Restated Credit Agreement due August 2016. The A&R Revolving Credit Facility matures on October 2, 2017, is guaranteed by all of Opco’s wholly owned subsidiaries, and is secured by liens on certain of the assets of Opco and its subsidiaries, as further described below.
Initially, indebtedness under the A&R Revolving Credit Facility bears interest, at Opco's option, at a rate of either:
• | the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus 2.375%; or |
• | a rate equal to LIBOR plus 3.375% |
Borrowings under the A&R Revolving Credit Facility will bear interest at such rate until the time that Opco delivers quarterly financial statements for the year ended December 31, 2015 to the lenders thereunder. Following such delivery date, indebtedness under the A&R Revolving Credit Facility will bear interest, at Opco's option, at a rate of either:
• | the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus an applicable margin ranging from 1.50% to 2.50% or |
• | a rate equal to LIBOR plus an applicable margin ranging from 2.50% to 3.50% |
The weighted average interest rates for the borrowings outstanding under the A&R Revolving Credit Facility for the twelve months ended December 31, 2015 and year ended December 31, 2014 were 2.91% and 1.98%, respectively.
Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum. Opco may prepay all amounts outstanding under the A&R Revolving Credit Facility at any time without penalty.
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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The A&R Revolving Credit Facility contains financial covenants requiring Opco to maintain:
• | a leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the A&R Revolving Credit Facility) not to exceed: |
• | 4.0 to 1.0 for each fiscal quarter ending on or before March 31, 2016; |
• | 3.75 to 1.0 for each subsequent fiscal quarter ending on or before March 31, 2017; and |
• | 3.5 to 1.0 for each fiscal quarter ending on or after June 30, 2017; and |
• | a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease expense) of not less than 3.5 to 1.0. |
The A&R Revolving Credit Facility contains 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. Included in the investment covenant are restrictions upon Opco’s ability to acquire assets where Opco does not maintain certain levels of liquidity. The A&R Revolving Credit Facility also contains customary events of default, including cross-defaults under Opco’s senior notes (as described below).
The A&R Revolving Credit Facility is collateralized and secured by liens on certain of Opco’s assets with a carrying value of $709.9 million classified as Land, Mineral rights and Plant and equipment on the Partnership’s Consolidated Balance Sheet as of December 31, 2015. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than NRP Trona LLC (which owns a 49% non-controlling equity interest in Ciner Wyoming), (2) the personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties, (4) real property associated with certain of VantaCore’s construction aggregates mining operations, and (5) certain of Opco’s coal-related infrastructure assets.
Term Loan
During 2013, Opco entered into a $200.0 million Term Loan facility (the "Term Loan") with a maturity date of January 23, 2016. The weighted average interest rates for the debt outstanding under the term loan for the twelve months ended December 31, 2015 and 2014 were 2.19% and 2.22% respectively.
Opco repaid $101.0 million in principal under the Term Loan during the third quarter of 2013, and repaid an additional $24.0 million during the fourth quarter of 2014. In September 2015, Opco repaid the remaining $75.0 million on the term loan using borrowings under the A&R Revolving Credit Facility.
Senior Notes
Opco made principal payments of $80.8 million on its senior notes during the year ended December 31, 2015. The Note Purchase Agreements relating to Opco’s senior notes contain covenants requiring Opco to:
•Maintain a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters;
•not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and
•maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.
The 8.38% and 8.92% senior notes also provide that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00.
In connection with the entry into the A&R Revolving Credit Facility in June 2015, Opco entered into the Third Amendment to the Note Purchase Agreements (the "NPA Amendment") that provides for the security of the senior notes by the same collateral package pledged by Opco and its subsidiaries to secure the A&R Revolving Credit Facility, as described above. In addition, the
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NPA Amendment includes a covenant that provides that, in the event Opco or any of its subsidiaries is subject to any additional or more restrictive covenants under the agreements governing its material indebtedness (including the A&R Revolving Credit Facility, and all renewals, amendments or restatements thereof), such covenants shall be deemed to be incorporated by reference in the senior notes and the holders of the senior notes shall receive the benefit of such additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement.
NRP Oil and Gas Debt
Revolving Credit Facility
In August 2013, NRP Oil and Gas entered into a 5-year, $100.0 million senior secured, reserve-based revolving credit facility in order to fund capital expenditure requirements related to the development of the oil and gas assets in which it owns non-operated working interests. In connection with the closing of the Sanish Field acquisition in November 2014, the credit facility was amended to increase its size to $500.0 million with an initial borrowing base of $137.0 million, and the maturity date thereof was extended to November 2019.
The maximum amount available under the credit facility is subject to semi-annual redeterminations of the borrowing base in May and November of each year, based on the value of the proved oil and natural gas reserves of NRP Oil and Gas, in accordance with the lenders’ customary procedures and practices. NRP Oil and Gas and the lenders each have a right to one additional redetermination each year. In April 2015, the lenders completed their semi-annual redetermination of the borrowing base under the NRP Oil and Gas revolving credit facility and the $137.0 million borrowing base under that facility was redetermined to $105.0 million. In October 2015, the lenders under the NRP Oil and Gas revolving credit facility completed their semi-annual redetermination of the borrowing base under the NRP Oil and Gas revolving credit facility and the $105.0 million borrowing base was redetermined to $88.0 million. The Partnership repaid $25.0 million of outstanding borrowings under the NRP Oil and Gas revolving credit facility during the year ended December 31, 2015. At December 31, 2015 and 2014, there was $85.0 million and $110.0 million respectively, outstanding under the NRP Oil and Gas revolving credit facility.
The credit facility is secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. NRP Oil and Gas is the sole obligor under its revolving credit facility, and neither the Partnership nor any of its other subsidiaries is a guarantor of such facility. The weighted average interest rate for the debt outstanding under the credit facility for the twelve months ended December 31, 2015 and, 2014 was 2.50% and 2.37%, respectively.
Indebtedness under the NRP Oil and Gas credit facility bears interest, at the option of NRP Oil and Gas, at either:
• | the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus an applicable margin ranging from 0.50% to 1.50%; or |
• | a rate equal to LIBOR, plus an applicable margin ranging from 1.50% to 2.50%. |
NRP Oil and Gas incurs a commitment fee on the unused portion of the borrowing base under the credit facility at a rate ranging from 0.375% to 0.50% per annum.
The NRP Oil and Gas credit facility contains certain covenants, which, among other things, require the maintenance of:
• | a total leverage ratio (defined as the ratio of the total debt of NRP Oil and Gas to its EBITDAX) of not more than 3.5 to 1.0; and |
• | a minimum current ratio of 1.0 to 1.0. |
As of December 31, 2015 and 2014, NRP Oil and Gas was in compliance with the terms of the financial covenants contained in its credit facility.
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Consolidated Principal Payments
The consolidated principal payments due are set forth below (in thousands):
NRP LP | Opco | NRP Oil and Gas | ||||||||||||||||||||
Senior Notes | Senior Notes | Credit Facility | Credit Facility | Total | ||||||||||||||||||
2016 | $ | — | $ | 80,983 | $ | — | $ | — | $ | 80,983 | ||||||||||||
2017 | — | 80,983 | 290,000 | — | 370,983 | |||||||||||||||||
2018 | 425,000 | (1 | ) | 80,983 | — | — | 505,983 | |||||||||||||||
2019 | — | 76,366 | — | 85,000 | 161,366 | |||||||||||||||||
2020 | — | 54,938 | — | — | 54,938 | |||||||||||||||||
Thereafter | — | 212,820 | — | — | 212,820 | |||||||||||||||||
$ | 425,000 | $ | 587,073 | $ | 290,000 | $ | 85,000 | $ | 1,387,073 | |||||||||||||
(1) | The 9.125% senior notes due 2018 were issued at a discount and as of December 31, 2015 were carried at $422.9 million. |
11. Fair Value Measurements
The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amounts reported on our Consolidated Balance Sheets for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. The following table (in thousands) shows the carrying amount and estimated fair value of our other financial instruments:
December 31, 2015 | December 31, 2014 | ||||||||||||||
Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||
Assets | |||||||||||||||
Contracts receivable—affiliate, current and long-term (1) | $ | 4,891 | $ | 4,158 | $ | 4,870 | $ | 5,162 | |||||||
Debt and debt—affiliate | |||||||||||||||
NRP LP senior notes (2) | $ | 422,923 | $ | 277,313 | $ | 422,167 | $ | 423,780 | |||||||
Opco senior notes and utility local improvement obligation (1) | $ | 587,073 | $ | 383,065 | $ | 668,056 | $ | 672,740 | |||||||
Opco revolving credit facility and term loan facility (3) | $ | 290,000 | $ | 290,000 | $ | 275,000 | $ | 275,000 | |||||||
NRP Oil and Gas revolving credit facility (3) | $ | 85,000 | $ | 85,000 | $ | 110,000 | $ | 110,000 | |||||||
(1) | The Level 3 fair value is estimated by management using quotations obtained for comparable instruments on the closing trading prices near year end. |
(2) | The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near year end. |
(3) | The Level 3 fair value approximates the carrying amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty. |
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12. Related Party Transactions
Reimbursements to Affiliates of our General Partner
The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for expenses incurred on the Partnership’s behalf. Direct general and administrative expenses are charged to the Partnership as incurred. The Partnership also reimburses indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by the Partnership’s general partner and its affiliates, Quintana Minerals Corporation and Western Pocahontas Properties Limited Partnership ("WPPLP"). In addition, the Partnership receives non-cash equity contributions from its general partner related to compensation paid directly by the general partner and not reimbursed by the Partnership. These amounts are presented as non-cash equity contributions on the Partnership's Consolidated Statements of Partners' Capital.
The Partnership had Accounts payable—affiliates to Quintana Minerals Corporation of $1.1 million and $0.6 million at December 31, 2015 and 2014, respectively, for services provided by Quintana Minerals Corporation to the Partnership. The Partnership had Accounts payable—affiliates to WPPLP of $0.3 million and $0.4 million at December 31, 2015 and 2014, respectively.
Direct general and administrative expenses charged to the Partnership by its general partner for services performed by WPPLP and Quintana Minerals Corporation are as follows (in thousands):
For the Year Ended December 31, | ||||||||
2015 | 2014 | 2013 | ||||||
Operating and maintenance expenses—affiliates, net | 16,031 | 10,770 | 8,821 | |||||
General and administrative—affiliates | 5,312 | 3,258 | 3,286 | |||||
The Partnership also leases an office building in Huntington, West Virginia from WPPLP and pays $0.6 million in lease payments each year through December 31, 2018.
Cline Affiliates
Various companies controlled by Chris Cline, including Foresight Energy LP, lease coal reserves from the Partnership, and the Partnership also leases coal transportation assets to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest (unaudited) in the NRP's general partner, as well as approximately 0.5 million of NRP's common units (unaudited) at December 31, 2015. Coal related revenues from Foresight Energy totaled $86.6 million, $81.5 million and $88.4 million for the years ended December 31, 2015, 2014 and 2013, respectively.
As of December 31, 2015 and 2014, the Partnership had Accounts receivable—affiliates from Foresight Energy of $6.4 million and $9.2 million, respectively. As of December 31, 2015, the Partnership had received $82.6 million in minimum royalty payments to date that have been recorded as Deferred revenue—affiliates since they have not been recouped by Foresight Energy.
The Partnership owns and leases rail load out and associated facilities to Foresight Energy at Foresight Energy's Sugar Camp mine. The lease agreement is accounted for as a direct financing lease. Total projected remaining payments under the lease at December 31, 2015 were $81.2 million with unearned income of $35.4 million, and the net amount receivable was $45.9 million, of which $2.0 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets. Minimum lease payments are $5.0 million per year for the next five years and represent a $1.25 million per quarter in deficiency payment.
Total projected remaining payments under the lease at December 31, 2014 were $86.3 million with unearned income of $39.0 million and the net amount receivable was $47.3 million, of which $1.8 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliates on the accompanying Consolidated Balance Sheets.
The Partnership holds a contractual overriding royalty interest from a subsidiary of Foresight Energy that provides for payments based upon production from specific tons at Foresight Energy's Sugar Camp operations. This overriding royalty was accounted for as a financing arrangement and is reflected as an affiliate receivable. The net amount receivable under the agreement
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as of December 31, 2015 was $4.9 million, of which $1.5 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate. The net amount receivable under the agreement as of December 31, 2014 was $5.6 million, of which $1.1 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets.
During the years ended December 31, 2015, 2014 and 2013, the Partnership recognized a gain of $9.3 million, $5.7 million and $8.1 million, respectively on a reserve swap at Foresight Energy's Williamson mine. The gain is included in Coal, hard mineral royalty and other—affiliates revenues on the Consolidated Statements of Comprehensive Income. The Level 3 fair value of the reserves was estimated using a discounted cash flow model. The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and anticipated market royalty rates.
Long-Term Debt—Affiliate
Donald R. Holcomb, one of the Partnership’s directors, is a manager of Cline Trust Company, LLC, which owns approximately 0.54 million of the Partnership’s common units and $20.0 million in principal amount of the Partnership’s 9.125% Senior Notes due 2018. The members of the Cline Trust Company are four trusts for the benefit of the children of Chris Cline, each of which owns an approximately equal membership interest in the Cline Trust Company. Mr. Holcomb also serves as trustee of each of the four trusts. Cline Trust Company, LLC purchased the $20.0 million of the Partnership’s 9.125% Senior Notes due 2018 in the Partnership’s offering of $125.0 million additional principal amount of such notes in October 2014 at the same price as the other purchasers in that offering. The balance on this portion of the Partnership’s 9.125% Senior Notes due 2018 was $19.9 million as of December 31, 2015 and 2014 and is included in Long-term debt, net—affiliate on the accompanying Consolidated Balance Sheet.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd. ("Quintana Capital"), which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership adopted a formal conflicts policy that establishes the opportunities that will be pursued by the Partnership and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in the Partnership's conflicts policy.
At December 31, 2015, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal Corp ("Corsa")., a coal mining company traded on the TSX Venture Exchange that is one of the Partnership’s lessees in Tennessee. Corbin J. Robertson III, one of the Partnership’s directors, is Chairman of the Board of Corsa. Coal related revenues from Corsa totaled $3.1 million, $3.0 million and $4.6 million for the years ended December 31, 2015, 2014 and 2013, respectively.
As of December 31, 2015, the Partnership had recorded $0.3 million in minimum royalty payments to date as Deferred revenue—affiliates since they have not been recouped by Corsa. The Partnership also had Accounts receivable—affiliates totaling $0.2 million and $0.3 million from Corsa at December 31, 2015 and 2014, respectively.
A fund controlled by Quintana Capital owned a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. In 2013, Taggart was sold to Forge Group, and Quintana no longer retains an interest in Taggart or Forge. The Partnership owns and leases preparation plants to Forge, which operates the plants. The lease payments were based on the sales price for the coal that was processed through the facilities. The revenues from Taggart prior to the sale to Forge were $1.8 million for the year ended December 31, 2013.
WPPLP Production Royalty and Overriding Royalty
For the year ended December 31, 2015, the Partnership recorded $0.4 million in operating and maintenance expenses—affiliates related to a non-participating production royalty payable to WPPLP pursuant to a conveyance agreement entered into in 2007. These charges were zero for the years ended December 31, 2014 and 2013. The Partnership had Other assets—affiliate from WPPLP of $1.1 million and $0.0 million at December 31, 2015 and December 31, 2014, respectively related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine.
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13. Asset Retirement Obligations
The Partnership accrues a liability for legal asset retirement obligations based on an estimate of the timing and amount of settlement. The Partnership accrues for costs involving the ultimate closure of certain of its aggregate mining operations in accordance with its operating permits. These charges include costs of land reclamation, water drainage, and incremental direct administration cost of closing the operations. The Partnership also accrues for estimated costs relating to plugging wells in which it has a non-operation working interest. Upon initial recognition of an asset retirement obligation the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to depreciation, depletion, and amortization and the initial costs are depleted over the useful lives of the related assets.
The following table presents a reconciliation (in thousands) of the beginning and ending carrying amounts of the Partnership’s asset retirement obligations. The short-term balance of $0.0 million and $0.1 million at December 31, 2015 and 2014, respectively, is included in Accrued liabilities and the remaining balance is included in Other non-current liabilities in the Consolidated Balance Sheets. The Partnership does not have any assets that are legally restricted for purposes of settling these obligations.
For the Years Ended December 31, | ||||||||
2015 | 2014 | |||||||
Balance, January 1 | $ | 4,973 | $ | 39 | ||||
Liabilities incurred in current period, including aquisitions | 5 | 4,697 | ||||||
Accretion expense | 284 | 237 | ||||||
Acquisition related purchase price adjustments | (2,280 | ) | — | |||||
Balance, December 31 | $ | 2,982 | $ | 4,973 | ||||
14. Commitments and Contingencies
Legal
The Partnership is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a material effect on the Partnership’s financial position, liquidity or operations.
The purchase agreement for the acquisition of the Partnership’s interest in Ciner Wyoming, formerly OCI Wyoming, requires the Partnership to pay additional contingent consideration to Anadarko to the extent certain performance criteria described in the purchase agreement are met at Ciner Wyoming in any of the years 2013, 2014 or 2015. During the first quarters of 2014 and 2015, the Partnership paid $0.5 million and $3.8 million, respectively, in contingent consideration to Anadarko. As of December 31, 2015, the Partnership has estimated and recorded $7.2 million as an accrued liability on its consolidated Balance Sheet, payable in the first quarter of 2016 with respect to 2015. The Partnership has no obligation to pay contingent consideration with respect to any period after 2015.
In March 2014, Anadarko gave the Partnership written notice that it believed certain reorganization transactions conducted in 2013 within the OCI organization triggered an acceleration of the Partnership’s obligation under the purchase agreement with Anadarko to pay the additional contingent consideration in full and demanded immediate payment of such amount. The Partnership disagreed with Anadarko’s position in a written response provided to them in April 2014. In April 2015, Anadarko sent a written request for additional information regarding the OCI reorganization and indicated that they were still considering this claim against the Partnership. The Partnership responded in writing in May 2015 and does not believe the reorganization transactions triggered an obligation to pay the additional contingent consideration. The Partnership will continue to engage in discussions with Anadarko to resolve the issue to the extent necessary. However, if Anadarko were to pursue and prevail on such a claim, the Partnership would be required to pay an amount to Anadarko in excess of the amounts already paid, together with the $7.2 million accrual described above, up to the maximum amount of the additional contingent consideration, minus a deductible. Under the purchase agreement, the maximum cumulative amount of additional contingent consideration is an amount equal to the net present value of $50.0 million. Any additional amount paid by the Partnership would be considered to be additional acquisition consideration and added to Equity and other unconsolidated investments.
Since 2013, several citizen group lawsuits have been filed against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In
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each case, the mine on the subject property had been closed, the property had been reclaimed, and the state reclamation bond had been released. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations. A subsidiary of the Partnership has been named as a defendant in one of these lawsuits. Given the early stage of this ongoing litigation, the Partnership currently cannot reasonably estimate a range of potential loss, if any, related to this matter.
Hillsboro/Deer Run
On November 24, 2015, we filed a lawsuit against Foresight Energy’s subsidiary, Hillsboro Energy LLC ("Hillsboro"), in the Circuit Court of the Fourth Judicial Circuit in Montgomery County, Illinois. The lawsuit alleges, among other items, breach of contract by Hillsboro resulting from a wrongful declaration of force majeure at Hillsboro’s Deer Run mine in July 2015. In late March 2015, elevated carbon monoxide readings were detected at the Deer Run mine, and coal production at the mine was idled. In July 2015, we received the notice declaring a force majeure event at the mine as a result of the elevated carbon monoxide levels. The effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us minimum deficiency payments of $7.5 million per quarter, or $30.0 million per year. Foresight Energy's failure to make the deficiency payment with respect to the second, third and fourth quarters of 2015 resulted in a $16.2 million cash impact to us. Such amount will increase for each quarter during which mining operations continue to be idled. We do not currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended period or if the mine is permanently closed, our financial condition could be adversely affected.
Environmental Compliance
The operations the Partnership’s lessees’ conduct on its properties, as well as the aggregates/industrial minerals and oil and gas operations in which the Partnership has interests, are subject to federal and state environmental laws and regulations. See "Item 1. Business—Regulation and Environmental Matters." As an owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring on the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership makes regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. The Partnership believes that its lessees will be able to comply with existing regulations and does not expect that any lessee’s failure to comply with environmental laws and regulations to have a material impact on the Partnership’s financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on the Partnership related to its properties for the period ended December 31, 2015. The Partnership is not associated with any environmental contamination that may require remediation costs. However, the Partnership’s lessees do conduct reclamation work on the properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, the Partnership is not responsible for the costs associated with these reclamation operations. As an owner of working interests in oil and natural gas operations, the Partnership is responsible for its proportionate share of any losses and liabilities, including environmental liabilities, arising from uninsured and underinsured events. The Partnership is also responsible for losses and liabilities, including environmental liabilities that may arise from uninsured and underinsured events at its VantaCore operations.
15. Major Lessees
Revenues from lessees that exceeded ten percent of total revenues and other income for any of the periods presented below are as follows (in thousands except for percentages):
For the Years Ended December 31, | |||||||||||||||||||||
2015 | 2014 | 2013 | |||||||||||||||||||
Revenues | Percent | Revenues | Percent | Revenues | Percent | ||||||||||||||||
Foresight Energy | $ | 86,614 | 17.7 | % | $ | 81,546 | 20.4 | % | $ | 88,432 | 24.7 | % | |||||||||
Alpha Natural Resources | $ | 34,364 | 7.0 | % | $ | 48,783 | 12.2 | % | $ | 55,147 | 15.4 | % | |||||||||
All of the revenue related to the customers above is included in revenues of the Coal, Hard Mineral Royalty and Other segment.
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The Partnership had a significant concentration of revenues with Foresight Energy and Alpha Natural Resources. The exposure is currently spread out over a number of different mining operations and leases. During the year ended December 31, 2015, total revenues and other income from Alpha Natural Resources included a $6.0 million non-recurring lease assignment fee.
16. Long-Term Incentive Plans
GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the "Long-Term Incentive Plan") for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.
Phantom units are incentive based equity awards issued to employees over a vesting period that entitle the grantee to receive the cash equivalent to the value of a unit of our common units upon each vesting. The Partnership records compensation cost equal to the fair value of the award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. In addition, compensation cost for unvested phantom unit awards is adjusted quarterly for any changes in the Partnership’s unit price. Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the 20 trading days prior to the vesting date. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides otherwise.
In connection with the phantom unit awards, the Compensation, Nominating and Governance Committee also granted tandem Distribution Equivalent Rights ("DERs"), which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units between the date the units are granted and the vesting date. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.
A summary of activity in the outstanding grants during 2015 is as follows (in thousands):
Phantom Units | ||
Outstanding grants at January 1, 2015 | 115 | |
Grants during the period | 52 | |
Grants vested and paid during the period | (29 | ) |
Forfeitures during the period | (12 | ) |
Outstanding grants at December 31, 2015 | 126 | |
Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The Partnership recorded a credit to general and administrative expenses related to its Long-Term Incentive Plan of $3.4 million for the year ended December 31, 2015, due to the decline in the market price of the Partnership's common units during 2015. For the years ended December 31, 2014 and 2013 the Partnership recorded G&A expenses of $1.0 million and $9.6 million, respectively.
In connection with the Long-Term Incentive Plans, payments are typically made during the first quarter of the year. Payments of $4.4 million, $6.5 million and $7.0 million were made during the years ended December 31, 2015, 2014, and 2013, respectively. The grant date fair value was $4.2 million, $6.6 million and $7.8 million for awards in 2015, 2014 and 2013, respectively. The unaccrued cost associated with unvested outstanding grants and related DERs at December 31, 2015 and December 31, 2014, was $0.7 million and $5.2 million, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
17. Supplementary Unrestricted Subsidiary Information
The following is presented as supplementary data as required by the Indenture governing the NRP Senior Notes due 2018 (the "Indenture"). As described in Note 2. Summary of Significant Accounting Policies, in February 2016, the Partnership designated NRP Oil and Gas, a wholly owned subsidiary of NRP, as an Unrestricted Subsidiary for purposes of the Indenture. In addition, the Partnership has designated BRP LLC, a joint venture in which the Partnership owns a 51% interest, and Coval Leasing Company, LLC, a wholly owned subsidiary of BRP LLC, as Unrestricted Subsidiaries for purposes of the Indenture. The information below may not necessarily be indicative of the results of operations, or financial position had the subsidiaries operated as independent entities. There were no transactions between the Partnership and its Restricted Subsidiaries and its Unrestricted Subsidiaries. In accordance with the requirements of the Indenture, the following condensed consolidating financial information presents the financial condition and results of operations of the Partnership and its Restricted Subsidiaries and its Unrestricted Subsidiaries:
CONDENSED CONSOLIDATING BALANCE SHEETS
(in thousands)
December 31, 2015 | ||||||||||||
Unrestricted Subsidiaries of NRP | NRP and its Restricted Subsidiaries | Total | ||||||||||
ASSETS | ||||||||||||
Current assets (including affiliates) | $ | 21,540 | $ | 99,589 | $ | 121,129 | ||||||
Mineral rights, net | 134,445 | 959,582 | 1,094,027 | |||||||||
Equity in unconsolidated investment | — | 261,942 | 261,942 | |||||||||
Other non-current assets (including affiliates) | 2,287 | 204,690 | 206,977 | |||||||||
Total assets | $ | 158,272 | $ | 1,525,803 | $ | 1,684,075 | ||||||
LIABILITIES AND CAPITAL | ||||||||||||
Current portion of long-term debt, net | — | 80,983 | 80,983 | |||||||||
Other current liabilities (including affiliates) | 7,351 | 48,313 | 55,664 | |||||||||
Long-term debt, net (including affiliate) | 85,000 | 1,219,013 | 1,304,013 | |||||||||
Other non-current liabilities (including affiliates) | 4,703 | 165,770 | 170,473 | |||||||||
Partners' capital | 64,663 | 11,673 | 76,336 | |||||||||
Non-controlling interest | (3,445 | ) | 51 | (3,394 | ) | |||||||
Total liabilities and capital | $ | 158,272 | $ | 1,525,803 | $ | 1,684,075 | ||||||
December 31, 2014 | ||||||||||||
Unrestricted Subsidiaries of NRP | NRP and its Restricted Subsidiaries | Total | ||||||||||
ASSETS | ||||||||||||
Current assets (including affiliates) | $ | 23,842 | $ | 112,276 | $ | 136,118 | ||||||
Mineral rights, net | 446,938 | 1,334,914 | 1,781,852 | |||||||||
Equity in unconsolidated investment | — | 264,020 | 264,020 | |||||||||
Other non-current assets (including affiliates) | 4,156 | 258,578 | 262,734 | |||||||||
Total assets | $ | 474,936 | $ | 1,969,788 | $ | 2,444,724 | ||||||
LIABILITIES AND CAPITAL | ||||||||||||
Current portion of long-term debt, net | — | 80,983 | 80,983 | |||||||||
Other current liabilities (including affiliates) | 16,212 | 50,736 | 66,948 | |||||||||
Long-term debt, net (including affiliate) | 110,000 | 1,284,240 | 1,394,240 | |||||||||
Other non-current liabilities (including affiliates) | 5,193 | 177,205 | 182,398 | |||||||||
Partners' capital | 344,232 | 376,573 | 720,805 | |||||||||
Non-controlling interest | (701 | ) | 51 | (650 | ) | |||||||
Total liabilities and capital | $ | 474,936 | $ | 1,969,788 | $ | 2,444,724 | ||||||
33
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Year Ended December 31, 2015 | ||||||||||||
Unrestricted Subsidiaries of NRP | NRP and its Restricted Subsidiaries | Total | ||||||||||
Revenues | $ | 56,091 | $ | 432,758 | $ | 488,849 | ||||||
Operating expenses | 361,166 | 605,594 | 966,760 | |||||||||
Loss from operations | (305,075 | ) | (172,836 | ) | (477,911 | ) | ||||||
Other expense | 4,065 | 89,744 | 93,809 | |||||||||
Net loss | (309,140 | ) | (262,580 | ) | (571,720 | ) | ||||||
Add: comprehensive loss from unconsolidated investment and other | — | (1,693 | ) | (1,693 | ) | |||||||
Comprehensive loss | $ | (309,140 | ) | $ | (264,273 | ) | $ | (573,413 | ) | |||
Year Ended December 31, 2014 | ||||||||||||
Unrestricted Subsidiaries of NRP | NRP and its Restricted Subsidiaries | Total | ||||||||||
Revenues | $ | 56,840 | $ | 342,912 | $ | 399,752 | ||||||
Operating expenses | 41,754 | 169,079 | 210,833 | |||||||||
Income from operations | 15,086 | 173,833 | 188,919 | |||||||||
Other expense | 662 | 79,427 | 80,089 | |||||||||
Net income | 14,424 | 94,406 | 108,830 | |||||||||
Add: comprehensive loss from unconsolidated investment and other | — | (81 | ) | (81 | ) | |||||||
Comprehensive income | $ | 14,424 | $ | 94,325 | $ | 108,749 | ||||||
Year Ended December 31, 2013 | ||||||||||||
Unrestricted Subsidiaries of NRP | NRP and its Restricted Subsidiaries | Total | ||||||||||
Revenues | $ | 14,386 | $ | 343,731 | $ | 358,117 | ||||||
Operating expenses | 8,812 | 113,069 | 121,881 | |||||||||
Income from operations | 5,574 | 230,662 | 236,236 | |||||||||
Other expense | 39 | 64,119 | 64,158 | |||||||||
Net income | 5,535 | 166,543 | 172,078 | |||||||||
Add: comprehensive income from unconsolidated investment and other | — | 65 | 65 | |||||||||
Comprehensive income | $ | 5,535 | $ | 166,608 | $ | 172,143 | ||||||
18. Subsequent Events
The following represents material events that have occurred subsequent to December 31, 2015 through the time of the Partnership’s filing of its Annual Report on Form 10-K with the SEC:
Distribution Declared
On February 12, 2016, the Partnership paid a distribution of $0.45 per unit to unitholders of record on February 5, 2016.
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 18, 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 units of issued and outstanding common units were combined into one issued and outstanding common unit, without any change in the par value per unit. The reverse unit split reduced the
34
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
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.
Oil and Gas Royalty Properties Sale
In February 2016, the Partnership sold royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for $36.6 million in net cash proceeds and recorded a gain of $20.3 million. The sale included royalty and overriding royalty interests in approximately 765 gross producing wells as of December 31, 2015 and approximately 10% of our estimated proved reserves as of December 31, 2015, or 1,094 MBoe. The effective date of the sale was January 1, 2016.
Aggregate Royalty Properties Sale
In February 2016, we sold the aggregates reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee, which comprised approximately 27%, or 139 million tons, of our estimated aggregates reserves as of December 31, 2015 for $9.8 million in net cash proceeds and recorded a gain of $1.6 million. The effective date of the sale was February 1, 2016.
35
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
The Partnership prepared the following oil and gas information in accordance with the authoritative guidance for oil and gas extractive activities.
Capitalized Costs (in thousands):
For the Years Ended December 31, | |||||||
2015 | 2014 | ||||||
Proven properties | $ | 199,404 | $ | 392,153 | |||
Unproven properties | — | 46,400 | |||||
Total property, plant, and equipment | 199,404 | 438,553 | |||||
Accumulated depreciation, depletion, and amortization | (60,542 | ) | (18,993 | ) | |||
Net capitalized costs | $ | 138,862 | $ | 419,560 | |||
Costs incurred for property acquisitions, exploration, and development (in thousands):
For the Years Ended December 31, | |||||||
2015 | 2014 | ||||||
Property acquisitions | |||||||
Proven properties | $ | — | $ | 298,627 | |||
Unproven properties | — | 40,800 | |||||
Development | 29,080 | 5,340 | |||||
Total | $ | 29,080 | $ | 344,767 | |||
Results of Operations for Producing Activities (in thousands):
For the Years Ended December 31, | |||||||
2015 | 2014 | ||||||
Production revenue | $ | 49,201 | $ | 48,834 | |||
Royalty and overriding royalty revenue (1) | 4,364 | 10,732 | |||||
Total oil and gas related revenue | 53,565 | 59,566 | |||||
Operating costs and expense: | |||||||
Depreciation, depletion and amortization | 40,772 | 23,936 | |||||
Property, franchise and other taxes | 5,210 | 5,529 | |||||
Production costs | 12,871 | 12,544 | |||||
Impairment of oil and gas properties | 367,576 | — | |||||
Total operating costs and expense | 426,429 | 42,009 | |||||
Total income from operations | $ | (372,864 | ) | $ | 17,557 | ||
(1) | Includes $0.4 million and $1.9 million for the years ended December 31, 2015 and 2014, respectively of nonproduction revenues including lease bonus payments |
Estimated Proved Reserves
Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term "reasonable certainty" implies a high degree of confidence that the quantities of crude oil, natural gas liquids and/or natural gas actually recovered will equal or exceed the estimate. The Partnership estimated proved reserves as of December 31, 2015 and 2014 were prepared by Netherland, Sewell & Associates, Inc., the Partnership’s independent reserve engineer. To achieve reasonable certainty, Netherland Sewell employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of the Partnership’s proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole and production data and well test data. Netherland Sewell prepared its report covering properties representing 100% of the Partnership’s estimated proved reserves as of December 31 2015 and 2014. Prices were calculated using the unweighted average of the first-
36
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
day-of-the-month pricing for the twelve months ended December 31, 2015 and 2014. These prices were then adjusted for transportation and other costs. There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reserve engineers often arrive at different estimates for the same properties. A copy of Netherland Sewell’s summary report is included as Exhibit 99.2 to this Annual Report on Form 10-K.
The following tables shows our estimated domestic proved reserves and reserve additions and revisions:
Crude Oil (MBbl) | NGLs (MBbl) | Natural Gas (MMcf)(2) | Total Proved Reserves (MBoe)(3) | |||||||||
December 31, 2014 | 9,983 | 1,229 | 14,370 | 13,607 | ||||||||
Revisions of previous estimates | (1,451 | ) | 89 | 701 | (1,244 | ) | ||||||
Extensions, discoveries and other additions | 776 | 60 | 541 | 926 | ||||||||
Sales of properties | (98 | ) | — | (62 | ) | (108 | ) | |||||
Production | (1,136 | ) | (156 | ) | (2,226 | ) | (1,663 | ) | ||||
December 31, 2015 (1) | 8,074 | 1,222 | 13,324 | 11,518 | ||||||||
Proved developed reserves as of December 31, 2015 | 7,862 | 1,196 | 13,157 | 11,251 | ||||||||
Proved undeveloped reserves as of December 31, 2015 | 212 | 26 | 167 | 267 | ||||||||
Proved developed reserves as of December 31, 2014 | 8,930 | 1,098 | 13,161 | 12,221 | ||||||||
Proved undeveloped reserves as of December 31, 2014 | 1,053 | 131 | 1,209 | 1,386 | ||||||||
(1) | Includes reserves attributable to the Partnership's 51% member interest in BRP LLC. |
(2) | Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. |
(3) | Includes 10,063MBoe of estimated proved reserves attributable to the Partnership’s non-operated working interests in oil and natural gas properties in the Williston Basin, approximately 3% of which were proved undeveloped reserves. |
The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows (in thousands):
For the Years Ended December 31, | |||||||
2015 | 2014 | ||||||
Future cash inflows | $ | 364,352 | $ | 920,454 | |||
Less related future: | |||||||
Production costs | (164,649 | ) | (312,666 | ) | |||
Development and abandonment costs | (7,826 | ) | (20,072 | ) | |||
Future net cash flows before 10% discount | 191,877 | 587,716 | |||||
Discount to present value at a 10% annual rate | (75,524 | ) | (282,519 | ) | |||
Total standardized measure of discounted net cash flows | $ | 116,353 | $ | 305,197 | |||
37
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(Unaudited)
The table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves during the year ended December 31, 2015 (in thousands):
Beginning of the period | $ | 305,197 | |
Revisions to previous estimates: | |||
Changes in prices and costs | (188,946 | ) | |
Changes in quantities | (11,750 | ) | |
Changes in future development costs | (12,202 | ) | |
Previously estimated development costs incurred during the period | 29,080 | ||
Additions to proved reserves from extensions, discoveries and improved recovery, less related costs | 11,928 | ||
Purchases and sales of reserves in place, net | (3,851 | ) | |
Accretion of discount | 31,795 | ||
Sales of oil and gas, net of production costs | (35,112 | ) | |
Production timing and other | (9,786 | ) | |
Net increase (decrease) | (188,844 | ) | |
End of period | $ | 116,353 | |
38
NATURAL RESOURCE PARTNERS L.P.
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
Quarterly Financial Data
The following table summarizes quarterly financial data for 2015 and 2014 (in thousands, except per unit data):
2015 | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Total 2015 | ||||||||||||||||||
Total revenues and other income | $ | 109,677 | $ | 137,630 | $ | 125,479 | $ | 116,063 | $ | 488,849 | |||||||||||||
Depreciation, depletion and amortization | $ | 25,392 | $ | 30,660 | $ | 26,624 | $ | 18,152 | $ | 100,828 | |||||||||||||
Asset impairment | $ | — | $ | 3,803 | (1) | $ | 626,838 | (2) | $ | 50,953 | (3) | $ | 681,594 | ||||||||||
Income (loss) from operations | $ | 40,417 | $ | 55,920 | $ | (576,290 | ) | $ | 2,042 | $ | (477,911 | ) | |||||||||||
Net income (loss) | $ | 17,489 | $ | 32,578 | $ | (600,001 | ) | $ | (21,786 | ) | $ | (571,720 | ) | ||||||||||
Net income (loss) per limited partner unit | $ | 1.40 | $ | 2.50 | $ | (47.90 | ) | $ | (1.75 | ) | $ | (45.75 | ) | ||||||||||
Weighted average number of common units outstanding | 12,230 | 12,230 | 12,230 | 12,230 | 12,230 | ||||||||||||||||||
2014 | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Total 2014 | ||||||||||||||||||
Total revenues and other income | $ | 80,309 | $ | 90,561 | $ | 91,609 | $ | 137,273 | $ | 399,752 | |||||||||||||
Depreciation, depletion and amortization | $ | 14,647 | $ | 16,350 | $ | 18,621 | $ | 30,258 | $ | 79,876 | |||||||||||||
Asset impairment | $ | — | $ | 5,624 | (4) | $ | — | $ | 20,585 | (5) | 26,209 | ||||||||||||
Income from operations | $ | 52,439 | $ | 50,403 | $ | 55,027 | $ | 31,050 | $ | 188,919 | |||||||||||||
Net income | $ | 32,605 | $ | 31,407 | $ | 36,173 | $ | 8,645 | $ | 108,830 | |||||||||||||
Net income per limited partner unit | $ | 2.90 | $ | 2.80 | $ | 3.20 | $ | 0.70 | $ | 9.42 | |||||||||||||
Weighted average number of common units outstanding | 10,985 | 11,040 | 11,124 | 12,145 | 11,326 | ||||||||||||||||||
(1) | During the second quarter of 2015 we recorded a $2.3 million impairment expense related to a coal preparation plant and a $1.5 million impairment expense related to coal mineral rights. |
(2) | During the third quarter of 2015 we recorded $335.7 million of oil and gas property impairment, $247.8 million of coal property impairment and $43.4 million of aggregates property impairment. |
(3) | During the fourth quarter of 2015 we recorded $31.9 million of oil and gas property impairment, $8.2 million of coal property impairment, $5.5 million of goodwill impairment, $4.7 million related to coal processing and transportation assets as well as obsolete equipment at our Logan office as well as a $0.7 million impairment expense related to obsolete plant and equipment at VantaCore. |
(4) | During the second quarter of 2014, we recorded $5.6 million of intangible asset impairment related to an aggregates lease. |
(5) | During the fourth quarter of 2014, we recorded $16.8 million of coal property impairment and $3.0 million of aggregates property impairment as well as $0.8 million in impairment expense related to a coal preparation plant. that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows. |
39
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NATURAL RESOURCE PARTNERS L.P. | |||
By: | NRP (GP) LP, its general partner | ||
By: | GP NATURAL RESOURCE | ||
PARTNERS LLC, its general partner | |||
Date: March 14, 2016 | |||
By: | /s/ CORBIN J. ROBERTSON, JR. | ||
Corbin J. Robertson, Jr. | |||
Chairman of the Board and | |||
Chief Executive Officer | |||
(Principal Executive Officer) | |||
Date: March 14, 2016 | |||
By: | /s/ CRAIG W. NUNEZ | ||
Craig W. Nunez | |||
Chief Financial Officer and | |||
Treasurer | |||
(Principal Financial Officer) | |||
Date: March 14, 2016 | |||
By: | /s/ CHRISTOPHER J. ZOLAS | ||
Christopher J. Zolas | |||
Chief Accounting Officer | |||
(Principal Accounting Officer) | |||
40
ITEM 15. EXHIBITS
Exhibit Number | Description | ||
2.1 | — | Purchase Agreement, dated as of January 23, 2013, by and among Anadarko Holding Company, Big Island Trona Company, NRP Trona LLC and NRP (Operating) LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on January 25, 2013). | |
2.2 | — | Agreement and Plan of Merger, dated as of August 18, 2014, by and among VantaCore Partners LP, VantaCore LLC, the Holders named therein, Natural Resource Partners L.P., NRP (Operating) LLC and Rubble Merger Sub, LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on August 20, 2014). | |
2.3 | — | Interest Purchase Agreement, by and among NRP Oil and Gas LLC, Kaiser-Whiting, LLC and the Owners of Kaiser-Whiting, LLC dated as of October 5, 2014 (incorporated by reference to Current Report on Form 8-K filed on October 6, 2014). | |
3.1 | — | Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of September 20, 2010 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on September 21, 2010). | |
3.2 | — | Fifth Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of December 16, 2011 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on December 16, 2011). | |
3.3 | — | Fifth Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of October 31, 2013 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on October 31, 2013). | |
3.4 | — | Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17, 2002 (incorporated by reference to Exhibit 3.4 of Annual Report on Form 10-K for the year ended December 31, 2002). | |
3.5 | — | Certificate of Limited Partnership of Natural Resource Partners L.P.(incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 filed April 19, 2002, File No. 333-86582). | |
4.1 | — | Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed June 23, 2003). | |
4.2 | — | First Amendment, dated as of July 19, 2005, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on July 20, 2005). | |
4.3 | — | Second Amendment, dated as of March 28, 2007, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on March 29, 2007). | |
41
Exhibit Number | Description | ||
4.4 | — | First Supplement to Note Purchase Agreement, dated as of July 19, 2005 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on July 20, 2005). | |
4.5 | — | Second Supplement to Note Purchase Agreement, dated as of March 28, 2007 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 29, 2007). | |
4.6 | — | Third Supplement to Note Purchase Agreement, dated as of March 25, 2009 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 26, 2009). | |
4.7 | — | Fourth Supplement to Note Purchase Agreement, dated as of April 20, 2011 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on April 21, 2011). | |
4.8 | — | Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to Exhibit 4.5 to Current Report on Form 8-K filed June 23, 2003). | |
4.9 | — | Form of Series A Note (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed June 23, 2003). | |
4.10 | — | Form of Series B Note (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed June 23, 2003). | |
4.11 | — | Form of Series D Note (incorporated by reference to Exhibit 4.12 to Annual Report on Form 10-K filed February 28, 2007). | |
4.12 | — | Form of Series E Note (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed March 29, 2007). | |
4.13 | — | Form of Series F Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 7, 2009). | |
4.14 | — | Form of Series G Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 7, 2009). | |
4.15 | — | Form of Series H Note (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q filed May 5, 2011). | |
4.16 | — | Form of Series I Note (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q filed May 5, 2011). | |
4.17 | — | Form of Series J Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 15, 2011). | |
4.18 | — | Form of Series K Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on October 3, 2011). | |
4.19 | — | Registration Rights Agreement, dated as of January 23, 2013, by and among Natural Resource Partners L.P. and the Investors named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on January 25, 2013). | |
4.20 | — | Amendment No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated March 6, 2012 (incorporated by reference to Exhibit 4.1 to Quarterly Report on Form 10-Q filed on August 7, 2012). | |
42
Exhibit Number | Description | ||
4.21 | — | Indenture, dated September 18, 2013, by and among Natural Resource Partners L.P. and NRP Finance Corporation, as issuers, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 19, 2013). | |
4.22 | — | Form of 9.125% Senior Notes due 2018 (contained in Exhibit 1 to Exhibit 4.22). | |
4.23 | — | 9.125% Senior Note due 2018 in $20,000,000 aggregate principal amount issued by Natural Resource Partners L.P. and NRP Finance Corporation to Cline Trust Company, LLC, dated October 17, 2014 (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed on October 20, 2014). | |
4.24 | — | Third Amendment, dated as of June 16, 2015, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and the holders named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 18, 2015). | |
10.1 | — | Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 18, 2015). | |
10.2 | — | Contribution Agreement, dated as of September 20, 2010, by and among Natural Resource Partners L.P., NRP (GP) LP, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and NRP Investment L.P. (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on September 21, 2010). | |
10.3 | — | Natural Resource Partners Second Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on January 17, 2008). | |
10.4*** | — | Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.4 to Annual Report on Form 10-K for the year ended December 31, 2007). | |
10.5*** | — | Natural Resource Partners Annual Incentive Plan (incorporated by reference to Exhibit 10.4 to Annual Report on Form 10-K for the year ended December 31, 2002). | |
10.6 | — | First Amended and Restated Omnibus Agreement, dated as of April 22, 2009, by and among Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed May 7, 2009). | |
10.7 | — | Restricted Business Contribution Agreement, dated January 4, 2007, by and among Christopher Cline, Foresight Reserves LP, Adena Minerals, LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on January 4, 2007). | |
10.8 | — | Investor Rights Agreement, dated January 4, 2007, by and among NRP (GP) LP, GP Natural Resource Partners LLC, Robertson Coal Management and Adena Minerals, LLC (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on January 4, 2007). | |
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Exhibit Number | Description | ||
10.9 | — | Waiver Agreement, dated November 12, 2009, by and among Natural Resource Partners L.P., Great Northern Properties Limited Partnership, Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on November 13, 2009). | |
10.10 | — | Common Unit Purchase Agreement, dated January 23, 2013, by and among Natural Resource Partners, L.P. and the purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on January 25, 2013). | |
10.11 | — | Limited Liability Company Agreement of Ciner Wyoming LLC (formerly OCI Wyoming LLC), dated June 30, 2014 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed by Ciner Resources LP (formerly OCI Resources LP) on July 2, 2014). | |
10.12 | Amendment No. 1 to the Amended and Restated Limited Liability Company Agreement of Ciner Resource Partners LLC (formerly known as OCI Resource Partners LLC), dated November 5, 2015 (incorporated by reference to Exhibit 3.4 to Current Report on Form 8-K filed by Ciner Resources LP (formerly OCI Resources LP) on November 5, 2015). | ||
10.13 | — | Credit Agreement, dated as of August 12, 2013, among NRP Oil and Gas LLC, Wells Fargo Bank, N.A., as Administrative Agent, and Wells Fargo Securities, LLC as Sole Bookrunner and Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 13, 2013). | |
10.14 | — | First Amendment to Credit Agreement, dated effective as of December 19, 2013, among NRP Oil and Gas LLC, Wells Fargo Bank, N.A., as Administrative Agent, and Wells Fargo Securities, LLC as Sole Bookrunner and Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on December 20, 2013). | |
10.15 | Second Amendment to Credit Agreement entered into effective as of November 12, 2014 among NRP Oil and Gas LLC, each of the Lenders that is a signatory thereto, and Wells Fargo Bank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on November 14, 2014). | ||
10.16*** | Natural Resource Partners L.P. 2016 Cash Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on February 26, 2016). | ||
10.17*** | Form of Long-Term Incentive Award Agreement (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on February 26, 2016). | ||
10.18*** | Form of Long-Term Performance Award Agreement (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed on February 26, 2016). | ||
21.1+ | — | List of subsidiaries of Natural Resource Partners L.P. | |
23.1* | — | Consent of Ernst & Young LLP. | |
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Exhibit Number | Description | ||
23.2* | — | Consent of Deloitte & Touche LLP. | |
23.3+ | — | Consent of Netherland, Sewell & Associates, Inc. | |
31.1* | — | Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley. | |
31.2* | — | Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley. | |
32.1** | — | Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350. | |
32.2** | — | Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350. | |
95.1+ | — | Mine Safety Disclosure. | |
99.1 | — | Description of certain provisions of the Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed on September 21, 2010). | |
99.2+ | — | Report of Netherland, Sewell & Associates, Inc. | |
99.3+ | — | Financial Statements of Ciner Wyoming LLC as of and for the years ended December 31, 2015, 2014 and 2013. | |
101.INS* | — | XBRL Instance Document | |
101.SCH* | — | XBRL Taxonomy Extension Schema Document | |
101.CAL* | — | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF* | — | XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB* | — | XBRL Taxonomy Extension Labels Linkbase Document | |
101.PRE* | — | XBRL Taxonomy Extension Presentation Linkbase Document | |
* | Filed herewith | ||
** | Furnished herewith | ||
*** | Management compensatory plan or arrangement | ||
+ | Previously filed as an exhibit to the original Annual Report on Form 10‑K for the year ended December 31, 2015 filed on March 11, 2016. | ||
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