UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2014
OR
¨ |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number: 001-31465
NATURAL
RESOURCE PARTNERS L.P.
(Exact name of registrant as specified in its charter)
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Delaware |
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35-2164875 |
(State or other jurisdiction of
incorporation or organization) |
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(I.R.S. Employer
Identification No.) |
601 Jefferson Street, Suite 3600
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)
(713)
751-7507
(Registrants telephone number, including area code)
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 x 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 x No ¨
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 definition of accelerated filer, large accelerated filer, and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
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Large Accelerated Filer |
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x |
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Accelerated Filer |
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¨ |
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Non-accelerated Filer |
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¨ (Do not check if a smaller reporting company) |
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Smaller Reporting Company |
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¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes ¨ No x
At November 7, 2014 there were 122,278,412 Common Units outstanding.
TABLE OF CONTENTS
2
Forward-Looking Statements
Statements included in this Quarterly Report on Form 10-Q are forward-looking statements. In addition, we and our representatives may from time
to time make other oral or written statements that are also forward-looking statements.
Such forward-looking statements include, among
other things, statements regarding:
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our financial strategy; |
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prices of and demand for coal, hydrocarbons, aggregates and industrial minerals; |
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estimated revenues, expenses and results of operations; |
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the amount, nature and timing of capital expenditures; |
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our ability to make acquisitions; |
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our liquidity and access to capital; |
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projected production levels by our lessees; |
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OCI Wyomings trona mining and soda ash refinery operations; |
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our acquisition of VantaCore and the Kaiser-Francis assets; |
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the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes; and |
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global and U.S. economic conditions. |
These forward-looking statements speak only as of the
date hereof and are made based upon managements current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking
statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.
You should not put undue reliance on any forward-looking statements. See Item 1A. Risk Factors in our Annual Report on Form 10-K
for the year ended December 31, 2013 and Item 1A. Risk Factors in this Quarterly Report on Form 10-Q for important factors that could cause our actual results of operations or our actual financial condition to differ.
3
Part I. Financial Information
Item 1. Financial Statements
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit information)
ASSETS
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September 30, 2014 |
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December 31, 2013 |
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(Unaudited) |
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Current assets: |
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Cash and cash equivalents |
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$ |
78,126 |
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$ |
92,513 |
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Accounts receivable, net of allowance for doubtful accounts |
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33,954 |
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33,737 |
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Accounts receivable affiliates |
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10,547 |
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7,666 |
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Other |
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899 |
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1,691 |
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Total current assets |
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123,526 |
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135,607 |
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Land |
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24,338 |
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24,340 |
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Plant and equipment, net |
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22,839 |
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26,435 |
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Mineral rights, net |
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1,385,919 |
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1,405,455 |
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Intangible assets, net |
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58,696 |
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66,950 |
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Equity and other unconsolidated investments |
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262,414 |
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269,338 |
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Loan financing costs, net |
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9,841 |
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11,502 |
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Long-term contracts receivableaffiliate |
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50,411 |
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51,732 |
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Other assets |
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560 |
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497 |
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Total assets |
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$ |
1,938,544 |
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$ |
1,991,856 |
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LIABILITIES AND PARTNERS CAPITAL |
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Current liabilities: |
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Accounts payable and accrued liabilities |
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$ |
13,907 |
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$ |
8,659 |
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Accounts payable affiliates |
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485 |
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391 |
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Current portion of long-term debt |
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80,983 |
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80,983 |
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Accrued incentive plan expenses current portion |
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6,535 |
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8,341 |
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Property, franchise and other taxes payable |
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5,764 |
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7,830 |
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Accrued interest |
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20,376 |
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17,184 |
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Total current liabilities |
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128,050 |
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123,388 |
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Deferred revenue |
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153,931 |
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142,586 |
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Accrued incentive plan expenses |
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6,887 |
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10,526 |
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Other non-current liabilities |
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9,712 |
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14,341 |
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Long-term debt |
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1,017,498 |
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1,084,226 |
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Partners capital: |
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Common units outstanding: (111,351,722 and 109,812,408) |
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613,176 |
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606,774 |
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General partners interest |
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10,212 |
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10,069 |
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Non-controlling interest |
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(650 |
) |
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324 |
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Accumulated other comprehensive loss |
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(272 |
) |
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(378 |
) |
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Total partners capital |
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622,466 |
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616,789 |
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Total liabilities and partners capital |
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$ |
1,938,544 |
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$ |
1,991,856 |
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The accompanying notes are an integral part of these financial statements.
4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands, except per unit data)
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Three Months Ended September 30, |
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Nine Months Ended September 30, |
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2014 |
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2013 |
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2014 |
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2013 |
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(Unaudited) |
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Revenues and other income: |
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Coal related revenues |
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$ |
65,193 |
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$ |
62,004 |
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$ |
172,927 |
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$ |
207,236 |
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Aggregate related revenues |
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2,655 |
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3,789 |
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9,614 |
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9,662 |
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Oil and gas related revenues |
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9,601 |
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3,886 |
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37,481 |
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9,742 |
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Equity and other unconsolidated investment income |
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9,685 |
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7,238 |
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28,865 |
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22,168 |
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Property taxes |
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3,520 |
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4,009 |
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10,865 |
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11,805 |
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Other |
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955 |
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1,311 |
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2,727 |
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2,760 |
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Total revenues and other income |
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91,609 |
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82,237 |
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262,479 |
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263,373 |
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Operating expenses: |
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Depreciation, depletion and amortization |
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18,621 |
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17,852 |
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49,618 |
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50,025 |
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Asset impairments |
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5,624 |
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|
734 |
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General and administrative |
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7,664 |
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7,305 |
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22,550 |
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27,769 |
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Property, franchise and other taxes |
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4,767 |
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4,234 |
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15,836 |
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12,810 |
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Oil and gas lease operating expenses |
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2,147 |
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483 |
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6,359 |
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483 |
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Transportation costs |
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354 |
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455 |
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1,238 |
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1,242 |
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Royalty payments |
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3,029 |
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284 |
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3,385 |
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826 |
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Total operating expenses |
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36,582 |
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30,613 |
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104,610 |
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93,889 |
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Income from operations |
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55,027 |
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51,624 |
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157,869 |
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169,484 |
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Other income (expense) |
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Interest expense |
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(18,862 |
) |
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(15,516 |
) |
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(57,759 |
) |
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(44,619 |
) |
Interest income |
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8 |
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18 |
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75 |
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232 |
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Income before non-controlling interest |
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36,173 |
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36,126 |
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100,185 |
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125,097 |
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Non-controlling interest |
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Net income |
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$ |
36,173 |
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$ |
36,126 |
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$ |
100,185 |
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$ |
125,097 |
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Net income attributable to: |
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General partner |
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$ |
723 |
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$ |
723 |
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$ |
2,004 |
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$ |
2,502 |
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Limited partners |
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$ |
35,450 |
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$ |
35,403 |
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$ |
98,181 |
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$ |
122,595 |
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Basic and diluted net income per limited partner unit |
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$ |
0.32 |
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$ |
0.32 |
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$ |
0.89 |
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$ |
1.12 |
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Weighted average number of units outstanding |
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111,244 |
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109,812 |
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110,504 |
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109,507 |
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Comprehensive income |
|
$ |
36,543 |
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$ |
36,167 |
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$ |
100,291 |
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|
$ |
125,243 |
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|
The accompanying notes are an integral part of these financial statements.
5
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
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Nine Months Ended September 30, |
|
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2014 |
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|
2013 |
|
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|
(Unaudited) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
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Net income |
|
$ |
100,185 |
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|
$ |
125,097 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
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|
Depreciation, depletion and amortization |
|
|
49,618 |
|
|
|
50,025 |
|
Gain on reserve swap |
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|
(5,690 |
) |
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|
(8,149 |
) |
Equity and other unconsolidated investment income |
|
|
(28,865 |
) |
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|
(22,168 |
) |
Distributions of earnings from unconsolidated investments |
|
|
32,225 |
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|
24,113 |
|
Non-cash interest charge, net |
|
|
2,145 |
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|
1,454 |
|
Gain on sale of assets |
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|
(3 |
) |
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|
(551 |
) |
Asset impairment |
|
|
5,624 |
|
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|
734 |
|
Change in operating assets and liabilities: |
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|
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Accounts receivable |
|
|
(7,542 |
) |
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|
9,477 |
|
Other assets |
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|
750 |
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|
|
864 |
|
Accounts payable and accrued liabilities |
|
|
1,623 |
|
|
|
792 |
|
Accrued interest |
|
|
3,192 |
|
|
|
(2,598 |
) |
Deferred revenue |
|
|
11,345 |
|
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|
13,331 |
|
Accrued incentive plan expenses |
|
|
(5,445 |
) |
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|
(80 |
) |
Property, franchise and other taxes payable |
|
|
(2,066 |
) |
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|
(2,826 |
) |
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|
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|
|
|
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|
Net cash provided by operating activities |
|
|
157,096 |
|
|
|
189,515 |
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|
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|
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Cash flows from investing activities: |
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Acquisition of plant and equipment |
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(207 |
) |
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Acquisition of land, coal, other mineral rights and related intangibles |
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|
(768 |
) |
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|
(38,303 |
) |
Oil and gas capital expenditures |
|
|
(13,267 |
) |
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|
Acquisition of equity interests |
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|
|
|
|
|
(293,077 |
) |
Distributions from unconsolidated affiliates |
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|
3,633 |
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|
48,833 |
|
Proceeds from sale of assets |
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|
5 |
|
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|
559 |
|
Return on direct financing lease and contractual override |
|
|
910 |
|
|
|
841 |
|
|
|
|
|
|
|
|
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|
Net cash used in investing activities |
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|
(9,694 |
) |
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|
(281,147 |
) |
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|
|
|
|
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|
Cash flows from financing activities: |
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|
|
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Proceeds from loans |
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|
2,000 |
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|
547,020 |
|
Repayment of loans |
|
|
(69,175 |
) |
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|
(386,230 |
) |
Deferred financing costs |
|
|
|
|
|
|
(9,061 |
) |
Proceeds from issuance of common units |
|
|
24,826 |
|
|
|
75,000 |
|
Capital contribution by general partner |
|
|
507 |
|
|
|
1,531 |
|
Costs associated with equity transactions |
|
|
(601 |
) |
|
|
(60 |
) |
Distributions to partners |
|
|
(119,346 |
) |
|
|
(186,317 |
) |
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities |
|
|
(161,789 |
) |
|
|
41,883 |
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(14,387 |
) |
|
|
(49,749 |
) |
Cash and cash equivalents at beginning of period |
|
|
92,513 |
|
|
|
149,424 |
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
78,126 |
|
|
$ |
99,675 |
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information: |
|
|
|
|
|
|
|
|
Cash paid during the period for interest |
|
$ |
52,266 |
|
|
$ |
45,716 |
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
6
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL
(In thousands, except unit data)
(Unaudited)
|
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|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
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|
|
|
|
|
|
|
Common Units |
|
|
General Partner Amounts |
|
|
Non-Controlling Interest Amounts |
|
|
Accumulated Other Comprehensive Income (Loss) |
|
|
Total |
|
|
|
Units |
|
|
Amounts |
|
|
|
|
|
Balance at December 31, 2013 |
|
|
109,812,408 |
|
|
$ |
606,774 |
|
|
$ |
10,069 |
|
|
$ |
324 |
|
|
$ |
(378 |
) |
|
$ |
616,789 |
|
Issuance of common units |
|
|
1,539,314 |
|
|
|
24,826 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,826 |
|
Capital contribution |
|
|
|
|
|
|
|
|
|
|
507 |
|
|
|
|
|
|
|
|
|
|
|
507 |
|
Cost associated with equity transactions |
|
|
|
|
|
|
(601 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(601 |
) |
Distributions |
|
|
|
|
|
|
(116,005 |
) |
|
|
(2,367 |
) |
|
|
(974 |
) |
|
|
|
|
|
|
(119,346 |
) |
Net income |
|
|
|
|
|
|
98,181 |
|
|
|
2,004 |
|
|
|
|
|
|
|
|
|
|
|
100,185 |
|
Interest rate swap from unconsolidated investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
69 |
|
|
|
69 |
|
Loss on interest hedge |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37 |
|
|
|
37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106 |
|
|
|
100,291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2014 |
|
|
111,351,722 |
|
|
$ |
613,176 |
|
|
$ |
10,212 |
|
|
$ |
(650 |
) |
|
$ |
(272 |
) |
|
$ |
622,466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
7
NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation and Organization
The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted
accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting
principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the nine months ended
September 30, 2014 are not necessarily indicative of the results that may be expected for future periods.
You should refer to the
information contained in the footnotes included in Natural Resource Partners L.P.s 2013 Annual Report on Form 10-K in connection with the reading of these unaudited interim consolidated financial statements.
Natural Resource Partners L.P. (the Partnership) engages principally in the business of owning, managing and leasing a diversified
portfolio of mineral properties in the United States, including interests in coal, an equity investment in trona and soda ash, oil and gas, construction aggregates, frac sand and other natural resources. The Partnerships 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 mines, but leases its 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 various interests in oil and gas properties that are located in the Williston
Basin, the Appalachian Basin, Louisiana and Oklahoma. The Partnerships 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 owns aggregate reserves located in a number of states across the country, some of which are leased to third party operators who mine and sell the reserves in exchange for royalty payments. In addition, the Partnership owns
a 49% interest in OCI Wyoming LLC (OCI Wyoming), a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. See Note 4. Equity and Other Investments for more information concerning this investment.
The general partner of the Partnership is NRP (GP) LP, a Delaware limited partnership, whose general partner is GP Natural Resource
Partners LLC, a Delaware limited liability company.
8
2. Significant Accounting Policies Update
Reclassification
Certain reclassifications have been made to the Consolidated Statements of Comprehensive Income. Amounts relating to prior years coal
royalties, processing fees, transportation fees, minimums recognized as revenue, override royalties and other have been reclassified into a single line item Coal related revenues on this years Consolidated Statements of
Comprehensive Income. Amounts relating to prior years aggregates royalties, processing fees, minimums recognized as revenue, override royalties and other have been reclassified into a single line item Aggregates related revenues on
this years Consolidated Statements of Comprehensive Income. The following is reclassification reconciliation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2013 |
|
|
Nine Months Ended September 30, 2013 |
|
|
|
As Reported |
|
|
As Reclassified |
|
|
As Reported |
|
|
As Reclassified |
|
|
|
Total |
|
|
Coal Related Revenues |
|
|
Aggregate Related Revenues |
|
|
Total |
|
|
Coal Related Revenues |
|
|
Aggregate Related Revenues |
|
|
|
(In thousands)
(Unaudited) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal royalties |
|
$ |
52,305 |
|
|
$ |
52,305 |
|
|
$ |
|
|
|
$ |
164,957 |
|
|
$ |
164,957 |
|
|
$ |
|
|
Equity and other unconsolidated investment income |
|
|
7,238 |
|
|
|
|
|
|
|
|
|
|
|
22,168 |
|
|
|
|
|
|
|
|
|
Aggregate royalties |
|
|
2,566 |
|
|
|
|
|
|
|
2,566 |
|
|
|
5,869 |
|
|
|
|
|
|
|
5,869 |
|
Processing fees |
|
|
1,377 |
|
|
|
1,263 |
|
|
|
114 |
|
|
|
3,886 |
|
|
|
3,511 |
|
|
|
375 |
|
Transportation fees |
|
|
4,742 |
|
|
|
4,742 |
|
|
|
|
|
|
|
13,499 |
|
|
|
13,499 |
|
|
|
|
|
Oil and gas royalties |
|
|
3,886 |
|
|
|
|
|
|
|
|
|
|
|
9,742 |
|
|
|
|
|
|
|
|
|
Property taxes |
|
|
4,009 |
|
|
|
|
|
|
|
|
|
|
|
11,805 |
|
|
|
|
|
|
|
|
|
Minimums recognized as revenue |
|
|
998 |
|
|
|
626 |
|
|
|
372 |
|
|
|
6,425 |
|
|
|
5,613 |
|
|
|
812 |
|
Override royalties |
|
|
2,927 |
|
|
|
2,269 |
|
|
|
658 |
|
|
|
11,011 |
|
|
|
8,713 |
|
|
|
2,298 |
|
Other |
|
|
2,189 |
|
|
|
799 |
|
|
|
79 |
|
|
|
14,011 |
|
|
|
10,943 |
|
|
|
308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
82,237 |
|
|
$ |
62,004 |
|
|
$ |
3,789 |
|
|
$ |
263,373 |
|
|
$ |
207,236 |
|
|
$ |
9,662 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recent Accounting Pronouncements
In May 2014, the FASB amended revenue recognition topics and created a new topic relating to revenue recognition that will supersede existing
guidance under U.S. GAAP. The core principle of the new guidance is to recognize revenue when promised goods or services are transferred to the customer and in an amount that reflects the consideration expected in exchange for those goods or
services. To achieve this core principle, an entity should (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the
transaction price to the performance obligations in the contract and (5) recognize revenue when each performance obligation is satisfied. The guidance also specifies the accounting for some costs to obtain or fulfill a contract with a
customer. Disclosure requirements include sufficient qualitative and quantitative information to enable financial statement users to understand the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with
customers. The new topic is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The guidance allows for either full adoption or a modified retrospective adoption. The
Partnership is currently evaluating the requirements to determine the impact, if any, of this new topic on its financial position, results of operations and cash flows.
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on
the Partnerships financial position, results of operations or cash flows.
3. Recent Acquisitions
Sundance. On December 19, 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. On August 9, 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.
Abraxas and Sundance combined revenues of $28.6 million and lease operating expenses of $6.4 million for the nine months ended
September 30, 2014 are included in Oil and gas related revenues and Oil and gas lease operating expenses, respectively, in the accompanying Consolidated Statements of Comprehensive Income.
9
4. Equity and Other Investments
The following summarized results of operations were taken from the OCI Wyoming-prepared unaudited financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating results: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands)
(Unaudited) |
|
Sales |
|
$ |
109,785 |
|
|
$ |
105,567 |
|
|
$ |
338,996 |
|
|
$ |
324,559 |
|
Gross profit |
|
$ |
28,487 |
|
|
$ |
20,545 |
|
|
$ |
83,210 |
|
|
$ |
63,860 |
|
Net income |
|
$ |
22,795 |
|
|
$ |
16,323 |
|
|
$ |
67,952 |
|
|
$ |
53,281 |
|
|
|
|
|
|
Income allocation to NRPs equity interests |
|
$ |
11,170 |
|
|
$ |
7,951 |
|
|
$ |
33,300 |
|
|
$ |
24,113 |
|
Less amortization of basis difference |
|
|
(1,485 |
) |
|
|
(713 |
) |
|
|
(4,435 |
) |
|
|
(1,945 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity and other unconsolidated investment income |
|
$ |
9,685 |
|
|
$ |
7,238 |
|
|
$ |
28,865 |
|
|
$ |
22,168 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For both the three and nine months ended September 30, 2014, the Partnership derived 11% of its revenues
and other income from its equity investment in OCI Wyoming. For the same periods of 2013, the Partnership derived 9% and 8%, respectively, of its revenues and other income from its equity investment in OCI Wyoming.
The terms of the OCI Wyoming acquisition agreement included provisions for the payment of contingent consideration to Anadarko Holding Company
if OCI Wyoming achieves certain earnings results in 2013, 2014 or 2015. The Partnership projected that the contingency would be $15 million at December 31, 2013.
The Partnerships contingent consideration consists of the following:
|
|
|
|
|
|
|
September 30, 2014 |
|
|
|
(In thousands) (Unaudited) |
|
Contingent consideration, January 1, 2014 |
|
$ |
15,000 |
|
Less: consideration paid during the period |
|
|
(491 |
) |
|
|
|
|
|
Contingent consideration, end of the period |
|
|
14,509 |
|
Less: current portion of contingent consideration |
|
|
(4,900 |
) |
|
|
|
|
|
Long-term contingent consideration |
|
$ |
9,609 |
|
|
|
|
|
|
The current portion is included in Accounts payable and accrued liabilities and the long term portion is
included in Other non-current liabilities on the accompanying Consolidated Balance Sheets.
In March 2014, Anadarko Holding Company
(Anadarko) gave written notice to the Partnership that Anadarko believes the reorganization transactions that occurred at OCI Wyoming in July 2013 triggered an acceleration of the Partnerships obligation to pay the additional contingent
consideration in full and demanded immediate payment of such amount. The Partnership does not believe the reorganization transactions triggered an obligation to pay the additional contingent consideration, and the Partnership will continue to engage
in discussions with Anadarko to resolve the issue. However, if Anadarko were to prevail on such claim, the Partnership would be required to pay an amount to Anadarko in excess of the $15 million contingency described above up to the net present
value of $50 million (the maximum amount of the additional contingent consideration). Any such additional amount would be considered to be additional acquisition consideration and added to Equity and other unconsolidated investments.
10
5. Plant and Equipment
The Partnerships plant and equipment consist of the following:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2014 |
|
|
December 31, 2013 |
|
|
|
(In thousands) |
|
|
|
(Unaudited) |
|
|
|
|
Work in process |
|
$ |
207 |
|
|
$ |
|
|
Plant and equipment at cost |
|
|
55,271 |
|
|
|
55,271 |
|
Less accumulated depreciation |
|
|
(32,639 |
) |
|
|
(28,836 |
) |
|
|
|
|
|
|
|
|
|
Net book value |
|
$ |
22,839 |
|
|
$ |
26,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands)
(Unaudited) |
|
Total depreciation expense on plant and equipment |
|
$ |
3,803 |
|
|
$ |
4,698 |
|
|
|
|
|
|
|
|
|
|
6. Mineral Rights
The Partnerships mineral rights consist of the following:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2014 |
|
|
December 31, 2013 |
|
|
|
(In thousands) |
|
|
|
(Unaudited) |
|
|
|
|
Mineral rights |
|
$ |
1,918,570 |
|
|
$ |
1,894,920 |
|
Less accumulated depletion and amortization |
|
|
(532,651 |
) |
|
|
(489,465 |
) |
|
|
|
|
|
|
|
|
|
Net book value |
|
$ |
1,385,919 |
|
|
$ |
1,405,455 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands) |
|
|
|
(Unaudited) |
|
Total depletion and amortization expense on mineral rights |
|
$ |
43,185 |
|
|
$ |
42,671 |
|
|
|
|
|
|
|
|
|
|
On April 7, 2014, one of the Partnerships lessees, James River Coal Company, filed for protection
under Chapter 11 of the U.S. Bankruptcy Code. At end of the second quarter of 2014, the net book value of the Partnerships properties leased to James River was approximately $35 million, net of previously paid minimums. During the third
quarter, certain of the leases, with a book value of $17 million net of previously paid minimums, were sold to Blackhawk Mining, which was already a lessee of the Partnership. Certain of the James River assets, some of which are subject to the
Partnerships leases, are still in bankruptcy and are in the process of being sold. If those remaining Partnership leases are rejected in the bankruptcy or if mining operations on the Partnerships properties cease, the Partnership may
determine that some or all of such properties are impaired. In the first nine months of 2014, those James River leases which remain in bankruptcy accounted for less than 1% of total revenues and other income, and for the year ended December 31,
2013, such leases represented less than 1% of total revenues and other income. The Partnership does not expect the resolution of the bankruptcy with regard to the remaining leases to have a material impact on its revenues and other income. The
Partnership will continue to monitor these properties for potential impairment as the bankruptcy proceedings progress.
11
7. Intangible Assets
Amounts recorded as intangible assets along with the balances and accumulated amortization are reflected in the table below:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2014 |
|
|
December 31, 2013 |
|
|
|
(In thousands) |
|
|
|
(Unaudited) |
|
|
|
|
Contract intangibles |
|
$ |
83,700 |
|
|
$ |
89,421 |
|
Less accumulated amortization |
|
|
(25,004 |
) |
|
|
(22,471 |
) |
|
|
|
|
|
|
|
|
|
Net book value |
|
$ |
58,696 |
|
|
$ |
66,950 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands)
(Unaudited) |
|
Total amortization expense on intangible assets |
|
$ |
2,630 |
|
|
$ |
2,656 |
|
|
|
|
|
|
|
|
|
|
During the second quarter of 2014, the Partnership recognized an impairment expense of $5.6 million relating
to an above market contract on an aggregates property. The asset impairment expense is included in Operating costs and expenses on the accompanying Consolidated Statements of Comprehensive Income.
The estimates of future amortization expense relating to intangible assets for the periods indicated below are based on current mining plans,
which are subject to revision in future periods.
|
|
|
|
|
|
|
Estimated Amortization Expense |
|
|
|
(In thousands) |
|
|
|
(Unaudited) |
|
Remainder of 2014 |
|
$ |
466 |
|
For year ended December 31, 2015 |
|
|
3,513 |
|
For year ended December 31, 2016 |
|
|
3,470 |
|
For year ended December 31, 2017 |
|
|
3,470 |
|
For year ended December 31, 2018 |
|
|
3,470 |
|
12
8. Long-Term Debt
As used in this Note 8, references to NRP LP refer to Natural Resource Partners L.P. only, and not to NRP
(Operating) LLC or any of Natural Resource Partners L.P.s other 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.
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2014 |
|
|
December 31, 2013 |
|
|
|
(In thousands) |
|
NRP LP Debt: |
|
(Unaudited) |
|
|
|
|
$300 million 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018, issued at
99.007% |
|
$ |
297,617 |
|
|
$ |
297,170 |
|
|
|
|
Opco Debt: |
|
|
|
|
|
|
|
|
$300 million floating rate revolving credit facility, due August 2016 |
|
|
7,000 |
|
|
|
20,000 |
|
$200 million floating rate term loan, due January 2016 |
|
|
99,000 |
|
|
|
99,000 |
|
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June
2018 |
|
|
18,467 |
|
|
|
23,084 |
|
8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in
March 2019 |
|
|
107,143 |
|
|
|
128,571 |
|
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July
2020 |
|
|
46,154 |
|
|
|
53,846 |
|
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021 |
|
|
1,346 |
|
|
|
1,538 |
|
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June
2023 |
|
|
24,300 |
|
|
|
27,000 |
|
4.73% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014,
maturing in December 2023 |
|
|
75,000 |
|
|
|
75,000 |
|
5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in
March 2024 |
|
|
150,000 |
|
|
|
165,000 |
|
8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014,
maturing in March 2024 |
|
|
45,454 |
|
|
|
50,000 |
|
5.03% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014,
maturing in December 2026 |
|
|
175,000 |
|
|
|
175,000 |
|
5.18% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014,
maturing in December 2026 |
|
|
50,000 |
|
|
|
50,000 |
|
|
|
|
NRP Oil and Gas Debt: |
|
|
|
|
|
|
|
|
Reserve-based floating rate revolving credit facility due August 2018 |
|
|
2,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt |
|
|
1,098,481 |
|
|
|
1,165,209 |
|
Less current portion of long term debt |
|
|
(80,983 |
) |
|
|
(80,983 |
) |
|
|
|
|
|
|
|
|
|
Long-term debt |
|
$ |
1,017,498 |
|
|
$ |
1,084,226 |
|
|
|
|
|
|
|
|
|
|
NRP LP Debt
Senior Notes. In September 2013, NRP LP, together with NRP Finance as co-issuer, issued $300 million of 9.125% senior notes at an
offering price of 99.007% of par value. Net proceeds after expenses related to the issuance of the senior notes of approximately $289.0 million were used to repay all of the outstanding borrowings under Opcos revolving credit facility and
$91.0 million of Opcos term loan. The senior notes call for semi-annual interest payments on April 1 and October 1 of each year. The notes will mature on October 1, 2018.
The indenture for the senior notes 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 LPs unsecured indebtedness exceeds certain thresholds.
13
Opco Debt
Senior Notes. Opco made principal payments of $56.0 million on its senior notes during the nine months ended September 30, 2014.
The Opco senior note purchase agreement contains 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 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 Opcos leverage ratio 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.
Revolving Credit Facility. The weighted average interest rates for the debt outstanding under Opcos
revolving credit facility for the nine months ended September 30, 2014 and year ended December 31, 2013 were 1.96% and 2.23%, respectively. Opco incurs a commitment fee on the undrawn portion of the revolving credit facility at rates
ranging from 0.18% to 0.40% per annum. The facility includes an accordion feature whereby Opco may request its lenders to increase their aggregate commitment to a maximum of $500 million on the same terms. At September 30, 2014 Opco had $7
million drawn under the credit facility.
Opcos revolving credit facility contains covenants requiring Opco to maintain:
|
|
|
a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to exceed 4.0 to 1.0 and, |
|
|
|
a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of not less than 3.5 to 1.0 for the four most recent quarters.
|
Term Loan Facility. During 2013, Opco issued $200 million in term debt. The weighted average interest rates for the
debt outstanding under the term loan for the nine months ended September 30, 2014 and the year ended December 31, 2013 were 2.23% and 2.43%, respectively. Opco repaid $101 million in principal under the term loan during the third quarter
of 2013. Repayment terms call for the remaining outstanding balance of $99 million to be paid in January 2016. The debt is unsecured but guaranteed by the subsidiaries of Opco.
Opcos term loan contains covenants requiring Opco to maintain:
|
|
|
a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to exceed 4.0 to 1.0 and, |
|
|
|
a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of not less than 3.5 to 1.0 for the four most recent quarters.
|
NRP Oil and Gas Debt
Revolving Credit Facility. In August 2013, NRP Oil and Gas entered into a 5-year, $100 million senior secured, reserve-based revolving
credit facility in order to fund capital expenditure requirements related to the development of non-operated working interests in oil and gas assets. The credit facility had a borrowing base of $20.0 million as of September 30, 2014 and is
secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. At September 30, 2014, there was $2.0 million outstanding under the credit facility. The weighted average interest rate for the debt
outstanding under the credit facility for the nine months ended September 30, 2014 was 1.90%.
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 1.75% to 2.75%. |
14
NRP Oil and Gas will incur 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. |
Consolidated Principal Payments
The consolidated principal payments due as of September 30, 2014 are set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRP LP |
|
|
Opco |
|
|
NRP Oil & Gas |
|
|
|
|
|
|
Senior Notes |
|
|
Senior Notes |
|
|
Credit Facility |
|
|
Term Loan |
|
|
Credit Facility |
|
|
Total |
|
|
|
(In thousands)
(Unaudited) |
|
2014 |
|
$ |
|
|
|
$ |
24,808 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
24,808 |
|
2015 |
|
|
|
|
|
|
80,983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80,983 |
|
2016 |
|
|
|
|
|
|
80,983 |
|
|
|
7,000 |
|
|
|
99,000 |
|
|
|
|
|
|
|
186,983 |
|
2017 |
|
|
|
|
|
|
80,983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80,983 |
|
2018 |
|
|
300,000 |
(1) |
|
|
80,983 |
|
|
|
|
|
|
|
|
|
|
|
2,000 |
|
|
|
382,983 |
|
Thereafter |
|
|
|
|
|
|
344,124 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
344,124 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
300,000 |
|
|
$ |
692,864 |
|
|
$ |
7,000 |
|
|
$ |
99,000 |
|
|
$ |
2,000 |
|
|
$ |
1,100,864 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
The 9.125% senior notes due 2018 were issued at a discount and as of September 30, 2014 were carried at $297.6 million. |
NRP LP, Opco and NRP Oil and Gas were in compliance with all terms under their long-term debt as of September 30, 2014.
9. Fair Value
The Partnerships financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and
long-term debt. The carrying amount of the Partnerships financial instruments included in accounts receivable and accounts payable in the accompanying Consolidated Balance Sheets approximates their fair value due to their short-term nature
except for the Accounts receivable affiliates relating to the Sugar Camp override that includes both current and long-term portions. The Partnerships cash and cash equivalents include money market accounts and are considered a
Level 1 measurement. The fair market value and carrying value of the contractual override and long-term senior notes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value As Of |
|
|
Carrying Value As Of |
|
|
|
September 30, 2014 |
|
|
December 31, 2013 |
|
|
September 30, 2014 |
|
|
December 31, 2013 |
|
|
|
(In thousands) |
|
|
|
(Unaudited) |
|
|
|
|
|
(Unaudited) |
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sugar Camp override, current and long-term |
|
$ |
6,534 |
|
|
$ |
6,852 |
|
|
$ |
6,227 |
|
|
$ |
6,063 |
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, current and long-term |
|
$ |
993,935 |
|
|
$ |
1,071,880 |
|
|
$ |
990,480 |
|
|
$ |
1,046,209 |
|
The fair value of the Sugar Camp override and long-term debt is estimated by management using comparable term
risk-free treasury issues with a market rate component determined by current financial instruments with similar characteristics which is a Level 3 measurement. Since the Partnerships credit facilities and term loan are variable rate debt,
their fair values approximate their carrying amounts.
15
10. Related Party Transactions
Reimbursements to Affiliates of the Partnerships General Partner
The Partnerships 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 Partnerships behalf. All 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 our general partner and its affiliates. The Partnership had an amount payable to Quintana Minerals Corporation of $0.5 million at September 30, 2014 for services provided by Quintana to the Partnership.
The reimbursements to affiliates of the Partnerships general partner for services performed by Western Pocahontas Properties and
Quintana Minerals Corporation are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands) |
|
|
|
(Unaudited) |
|
Reimbursement for services |
|
$ |
2,927 |
|
|
$ |
2,748 |
|
|
$ |
8,708 |
|
|
$ |
8,481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Partnership also leases an office building in Huntington, West Virginia from Western Pocahontas Properties
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, lease coal reserves from the Partnership, and the Partnership provides
coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest (unaudited) in the Partnerships general partner, as well as 4,917,548 common units
(unaudited) at September 30, 2014. At September 30, 2014, the Partnership had accounts receivable totaling $10.3 million from Cline affiliates. In addition, the overriding royalty and the lease of the loadout facility at Foresight
Energys Sugar Camp mine are classified as contracts receivable of $50.4 million on the Partnerships Consolidated Balance Sheets. The Partnership has received $82.7 million in minimum royalty payments that have not been recouped by Cline
affiliates, of which $11.7 million was received in the current year.
Coal related revenues from Cline affiliates were $24.9 million and
$21.0 million and $63.1 million and $68.4 million, for the three and nine months ended September 30, 2014 and 2013, respectively. For the nine months ending September 30, 2013, the results included $8.1 million from a reserve swap and $3.5
million from minimums that expired on Foresight Energys Macoupin mine and were recognized as revenue. For the nine months ended September 30, 2014 the results included $5.7 million from a reserve swap.
The Partnership entered into a lease agreement related to the rail loadout and associated facilities at Sugar Camp that has been accounted for
as a direct financing lease. Total projected remaining payments under the lease at September 30, 2014 are $87.6 million with unearned income of $40.0 million. The net amount receivable under the lease as of September 30, 2014 was $47.6
million, of which $1.8 million is included in Accounts receivable affiliates while the remaining is included in Long-term contracts receivable affiliate on the accompanying Consolidated Balance Sheets.
In a separate transaction, the Partnership acquired a contractual overriding royalty interest from a Cline affiliate that provides for
payments based upon production from specific tons at the 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
as of September 30, 2014 was $6.2 million, of which $1.6 million is included in Accounts receivable affiliates while the remaining is included in Long-term contracts receivable affiliate on the accompanying Consolidated Balance
Sheets.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., 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 Capitals affiliated investment funds reflect the guidelines set forth in the Partnerships conflicts policy.
16
At September 30, 2014, a fund controlled by Quintana Capital owned a majority interest in
Corsa Coal Corp., a coal mining company traded on the TSX Venture Exchange that is one of the Partnerships lessees in Tennessee. Corbin J. Robertson III, one of the Partnerships directors, is Chairman of the Board of Corsa. Revenues from
Corsa are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands)
(Unaudited) |
|
Coal royalty revenues |
|
$ |
655 |
|
|
$ |
1,249 |
|
|
$ |
2,218 |
|
|
$ |
3,403 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Partnership also had accounts receivable totaling $0.2 million from Corsa at September 30, 2014.
A fund controlled by Quintana Capital owned a significant membership interest in Taggart Global USA, LLC, including the right to nominate two
members of Taggarts 5-person board of directors. Subsequent to the end of the second quarter of 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.
Revenues from Forge for the nine months ended September 30, 2013 were $1.8 million. Subsequent to the end of the second quarter of 2013,
Taggart/Forge is no longer considered a related party of the Partnership.
11. 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 Partnerships financial position, liquidity or operations.
Environmental Compliance
The operations conducted on the Partnerships properties are subject to environmental laws and regulations adopted by various governmental
authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of
substantially all of the Partnerships 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 has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties as of September 30, 2014. The Partnership is not associated with any environmental contamination that may require
remediation costs.
17
12. Major Lessees
Revenues from lessees that exceeded ten percent of total revenues and other income for the periods are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
|
|
(Dollars in thousands)
(Unaudited) |
|
|
|
Revenues |
|
|
Percent |
|
|
Revenues |
|
|
Percent |
|
|
Revenues |
|
|
Percent |
|
|
Revenues |
|
|
Percent |
|
The Cline Group |
|
$ |
24,863 |
|
|
|
27 |
% |
|
$ |
21,046 |
|
|
|
26 |
% |
|
$ |
63,116 |
|
|
|
24 |
% |
|
$ |
68,359 |
|
|
|
26 |
% |
Alpha Natural Resources |
|
$ |
14,406 |
|
|
|
16 |
% |
|
$ |
12,937 |
|
|
|
16 |
% |
|
$ |
38,857 |
|
|
|
15 |
% |
|
$ |
41,844 |
|
|
|
16 |
% |
In the first nine months of 2014, the Partnership derived over 39% of its total revenues and other income from
the two companies listed above. The Partnership has a significant concentration of revenues with Cline and Alpha, although in most cases, with the exception of the Williamson mine, the exposure is spread out over a number of different mining
operations and leases. Foresight Energys Williamson mine was responsible for approximately 16% and 12%, respectively, of the Partnerships total revenues and other income for the three and nine months ended September 30, 2014.
13. 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, Nominating and Governance (CNG) Committee of GP Natural Resource Partners
LLCs 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 CNG 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.
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 last 20 trading days prior to the vesting date. The CNG 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 grantees employment or
membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the CNG Committee provides otherwise.
A summary of activity in the outstanding grants during 2014 is as follows:
|
|
|
|
|
|
|
(Unaudited) |
|
Outstanding grants at January 1, 2014 |
|
|
1,012,984 |
|
Grants during the year |
|
|
313,699 |
|
Grants vested and paid during the year |
|
|
(285,500 |
) |
Forfeitures during the year |
|
|
(28,460 |
) |
|
|
|
|
|
Outstanding grants at September 30, 2014 |
|
|
1,012,723 |
|
|
|
|
|
|
Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The liability
fluctuates with the market value of the Partnership units and because of changes in estimated fair value determined each quarter using the Black-Scholes option valuation model. Risk free interest rates and volatility are reset at each calculation
based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 0.12% to 1.06% and 28.80% to 29.92%, respectively at September 30, 2014. The Partnerships average distribution rate of 7.4% and
historical forfeiture rate of 5.2% were used in the calculation at September 30, 2014. The Partnership recorded expenses related to its plan to be reimbursed to its general partner of $1.1 million and $0.6 million for the three months ended
September 30, 2014 and 2013, respectively, and for the nine months ended September 30, 2014 and 2013 the Partnership recorded expense of $1.5 million and $7.5 million, respectively. In connection with the Long-Term Incentive Plan, payments
are typically made during the first quarter of the year. Payments of $6.5 million and $7.0 million were made during the nine month period ended September 30, 2014 and 2013, respectively.
18
In connection with the phantom unit awards, the CNG Committee also granted tandem Distribution
Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnerships common units. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases
employment prior to vesting.
The unaccrued cost, associated with the unvested outstanding grants and related DERs at September 30,
2014 was $7.7 million.
14. Shelf Registration Statements and At-the-Market Program
On April 24, 2012, the Partnership filed an automatically effective shelf registration statement on Form S-3 with the
SEC that is available for registered offerings of common units and debt securities.
On August 15, 2012, the Partnership filed a
shelf registration statement on Form S-3 that registered all of the common units held by Adena Minerals. This shelf registration statement was declared effective by the SEC on September 21, 2012. Following the effectiveness of this registration
statement, Adena distributed 15,181,716 common units to its shareholders, and the Partnership subsequently filed prospectus supplements to register the resale of these common units by those shareholders. The shelf registration statement filed in
August 2012 also registered up to $500 million in equity securities that may be issued by the Partnership. On November 12, 2013, the Partnership filed a prospectus supplement and entered into an Equity Distribution Agreement relating to the
offer and sale from time to time of common units having an aggregate offering price of $75 million through one or more managers acting as sales agents at prices to be agreed upon at the time of sale. Under the terms of the Equity Distribution
Agreement, the Partnership may also sell common units from time to time to any manager as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to any manager as principal would be pursuant to the
terms of a separate terms agreement between the Partnership and such manager. Sales of common units in this at-the-market (ATM) program are made pursuant to the shelf registration statement declared effective in September
2012. For the nine months ended September 30, 2014 the Partnership sold 1,539,314 common units for an average price of $16.13 for gross proceeds of $24.8 million. In addition, the Partnership paid the ATM program manager a fee of up to 2% of
the gross proceeds from the sale of common units under the ATM program.
On April 12, 2013, the Partnership filed a resale shelf
registration statement on Form S-3 to register the 3,784,572 common units issued in the January 2013 private placement related to funding of the OCI Wyoming acquisition. This shelf registration statement was declared effective by the SEC in May
2013. A portion of the common units issued in the private placement were issued, directly and indirectly, to certain of the Partnerships affiliates, including Corbin J. Robertson, Jr. and Christopher Cline.
15. Distributions
On August 14, 2014, the Partnership paid a quarterly distribution $0.35 per unit to all holders of common units on
August 5, 2014.
16. Subsequent Events
The following represents material events that have occurred subsequent to September 30, 2014 through the time of the
Partnerships filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission:
Distributions
On October 20, 2014, the Partnership declared a distribution of $0.35 per unit to be paid on November 14, 2014 to
holders of common units on November 5, 2014.
Distributions Received From Unconsolidated Equity and Other Investments
Subsequent to September 30, 2014, the Partnership received $10.8 million in cash distributions from its equity investment in
OCI Wyoming.
Kaiser-Francis Acquisition
On October 5, 2014, the Partnership entered into a definitive agreement to acquire non-operated working interests in oil and gas assets
located in the Bakken/Three Forks play from an affiliate of Kaiser-Francis Oil Company for $340 million, subject to customary purchase price adjustments. Upon entering into the agreement, the Partnership paid a deposit of $25 million. The assets
include approximately 5,700 net acres in the Sanish Field in Mountrail County, North Dakota and include an estimated average working interest of 15% in approximately 200 wells that are producing or in various stages of development in addition to the
opportunity to participate in future development locations. The assets are all held by production and are operated by Whiting Petroleum Corporation. The acquisition will have an effective date of October 1, 2014 and is expected to close in
mid-November 2014, subject to the satisfaction of customary closing conditions.
19
VantaCore Acquisition
On October 1, 2014, the Partnership completed its acquisition of VantaCore Partners LP (VantaCore), a privately held limited
partnership specializing in the construction materials industry, for $205 million in cash and common units, subject to customary post-closing purchase price adjustments. Headquartered in Philadelphia, Pennsylvania, VantaCore operates three hard rock
quarries, six sand and gravel plants, two asphalt plants and a marine terminal. VantaCores current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.
In order to fund the VantaCore acquisition, the Partnership borrowed $169 million under Opcos revolving credit facility and issued
approximately 2.4 million common units to certain of the sellers. The closing price of the Partnerships common units on the date of issuance was $13.02 per unit. The Partnerships general partners capital contribution to
maintain its 2% general partner interest in the Partnership was approximately $0.6 million.
Equity Offering
On October 10, 2014 the Partnership sold 8.5 million common units in an underwritten public offering registered under the Securities
Act of 1933, as amended, at a public offering price of $12.02 per common unit. In connection with the offering, the Partnership granted the underwriters a 30-day option to purchase up to 1,275,000 additional common units. The Partnership
intends to use the net proceeds of approximately $100.4 million from this offering, including its general partners proportionate capital contribution, to fund a portion of the purchase price of the Kaiser-Francis acquisition. The
Partnerships general partners capital contribution to maintain its 2% general partner interest in the Partnership was approximately $2.1 million.
Senior Notes
On October 17,
2014 the Partnership and NRP Finance Corporation (the Issuers) sold an additional $125 million aggregate principal amount of their 9.125% senior notes due 2018 in a private offering. The notes were issued pursuant to an indenture,
dated September 18, 2013, among the Issuers and Wells Fargo Bank, National Association, as trustee. The notes constitute the same series of securities as the existing $300 million 9.125% senior notes due October 2018 issued in
September 2013.
In the offering, $105 million in aggregate principal amount of the notes were sold in a private placement to the
initial purchasers thereof to be offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act, and to persons outside the United States pursuant to Regulation S under the Securities Act. The remaining $20
million in aggregate principal amount of the notes were sold in a separate private placement to Cline Trust Company, LLC, a Delaware limited liability company. The members of Cline Trust Company, LLC are four trusts of which the beneficiaries are
the children of Christopher Cline. Donald R. Holcomb, one of the members of the Board of Directors of GP Natural Resource Partners LLC, is a manager of Cline Trust Company, LLC and the trustee of each of the four trusts that are members of Cline
Trust Company, LLC.
20
Item 2. Managements Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion of the financial condition and results of operations should be read in conjunction with the
historical financial statements and notes thereto included elsewhere in this filing and the financial statements and footnotes included in the Natural Resource Partners L.P. Annual Report on Form 10-K for the year ended December 31, 2013, as
filed on February 28, 2014.
As used in this Item 2, unless the context otherwise requires: we,
our and us refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to NRP and Natural Resource Partners refer to Natural Resource Partners L.P. only, and
not to NRP (Operating) LLC 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. NRP Finance Corporation (NRP Finance) is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes.
Executive Overview
We engage principally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the United States,
including interests in coal, an equity investment in trona and soda ash, oil and gas, construction aggregates, frac sand and other natural resources. Executing on our plans to diversify our business, we have completed or announced over $900 million
in acquisitions since January 2013. For the nine months ended September 30, 2014, we recognized approximately $172.9 million (66%) of our revenues and other income from coal-related sources, and $89.6 million (34%) of our revenues and
other income from non-coal-related sources.
Our 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. As of December 31, 2013, we owned or controlled approximately 2.3 billion tons of proven and probable coal reserves. We do not operate any
mines, but lease our reserves to experienced mine operators under long-term leases that grant the operators the right to mine and sell our reserves in exchange for royalty payments. We also own and manage infrastructure assets that generate
additional revenues, primarily in the Illinois Basin.
We own various interests in oil and gas properties that are located in the
Williston Basin, the Appalachian Basin, Louisiana and Oklahoma. Our interests in the Appalachian Basin, Louisiana and Oklahoma are minerals and royalty interests, while in the Williston Basin we own non-operated working interests. On October 5,
2014, we entered into a definitive agreement to acquire additional non-operated working interests in oil and gas assets located in the Williston Basin from an affiliate of Kaiser-Francis Oil Company for $340 million in cash, subject to customary
purchase price adjustments. The assets include approximately 5,700 net acres in the Sanish Field in Mountrail County, North Dakota and include an estimated average working interest of 15% in approximately 200 wells that were producing or in various
stages of development as of the beginning of October 2014, in addition to the opportunity to participate in future development locations. The assets are all held by production and are operated by Whiting Petroleum Corporation. The acquisition is
expected to close in mid-November.
As of December 31, 2013, we owned approximately 500 million tons of aggregate reserves
located in a number of states across the country. Similar to our coal business, we lease these reserves to third party operators who mine and sell the reserves in exchange for royalty payments. On October 1, 2014, we acquired VantaCore Partners
LP (now VantaCore Partners LLC) (VantaCore) for $205 million in cash and common units, subject to customary post-closing purchase price adjustments. VantaCore specializes in the construction materials industry and operates three
hard rock quarries, six sand and gravel plants, two asphalt plants and a marine terminal. VantaCores current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. We internally estimate that VantaCore
controlled approximately 295 million tons of aggregates reserves as of December 31, 2013.
We also own a 49% interest in a trona
ore mining operation and soda ash refinery in the Green River Basin, Wyoming. OCI 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, and record the income in accordance with our 49% equity interest in the company.
In our coal and aggregates royalty businesses, our lessees generally make payments to us based on the greater of a percentage of the gross
sales price or a fixed royalty per ton of coal or aggregates they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time, which varies by lease, if sufficient
royalties are generated from production in those future periods. We do not recognize these minimum royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these
minimum royalties are recorded as deferred revenue, a liability on our balance sheet.
21
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. We also incur capital expenditures and operating expenses associated with the non-operated working interests in oil and gas assets. Oil and gas royalty revenues include production
payments as well as bonus payments. Oil and gas royalty revenues are recognized on the basis of hydrocarbons sold by lessees and the corresponding revenues from those sales. Generally, the lessees make payments based on a percentage of the selling
price.
Our Current Liquidity Position
As of September 30, 2014, Opco had $293.0 million in available borrowing capacity under its revolving credit facility. On October 1,
2014, Opco borrowed an additional $169.0 million thereunder to fund a portion of the purchase price of the VantaCore acquisition. Also as of September 30, 2014, NRP Oil and Gas had $18.0 million in available borrowing capacity under its
revolving credit facility. In connection with the closing of the Kaiser-Francis acquisition, NRP Oil and Gass revolving credit facility will be amended, and the borrowing base thereunder is expected to be increased to $137 million. We expect
to borrow up to $120 million thereunder to fund a portion of the purchase price of that acquisition. We typically access the capital markets to refinance amounts outstanding under our revolving credit facilities as we approach the limits under those
facilities, the timing of which depends on the pace and size of our acquisition program and development capital expenditures associated with our oil and gas business.
In addition to the amounts available under our revolving credit facilities, we had $78.1 million in cash as of September 30, 2014. As of
the date of this report, we have sold 1,539,314 common units through our at-the-market offering (ATM) program during 2014 for approximately $24.8 million in gross proceeds, excluding our general partners capital
contribution to maintain its 2% general partner interest in us. During the first nine months of 2014, we repaid $56.2 million of principal on Opcos senior notes and utility local improvement obligation, and repaid $13.0 million under
Opcos revolving credit facility. Because we intend to use cash to repay principal on Opcos notes rather than refinancing the amounts due, our current liabilities exceeded our current assets by approximately $4.5 million as of
September 30, 2014.
Subsequent to the end of the third quarter, we issued approximately 2.4 million common units to fund a
portion of the purchase price of the VantaCore acquisition. We also issued 8.5 million common units in a public offering of common units and sold an additional $125 million aggregate principal amount of our 9.125% senior notes due 2018 in a
private offering. We intend to use the net proceeds from these offerings, which totaled $222.5 million (including our general partners capital contribution to maintain its 2% general partner interest in us in connection with the common unit
offering), to fund a portion of the purchase price of the Kaiser-Francis acquisition.
We believe that the combination of our borrowing
capacity under our revolving credit facilities and our cash on hand gives us enough liquidity to meet our current financial needs. Other than $81.0 million in principal repayments due on Opcos senior notes each year for the next
several years (including $24.8 million of principal payments remaining in 2014), we do not have any debt maturing until 2016. While we intend to reduce our leverage by repaying such amounts with cash from operations and issuances of equity through
our ATM program, we may refinance such amounts as they come due.
Current Results/Market Outlook
Our total revenues and other income for the nine months ended September 30, 2014 were $262.5 million, which were essentially unchanged
from the $263.4 million in total revenues and other income earned for the nine months ended September 30, 2013. Although our total revenues and other income were down less than 1% from the first nine months of 2013, our coal related revenues
were down 17% compared to the same period. The majority of the decrease in coal-related revenues was due to lower Central Appalachian coal royalty revenues, which were down 15% from the first nine months of 2013. We continue to see the benefits of
our diversification efforts, as our revenues and other income from sources other than coal represented 34% of our total revenues and other income in the first nine months of 2014, up from approximately 21% of total revenues and other income in the
first nine months of 2013. During the first nine months of 2014, our investment in OCI Wyomings trona mining and soda ash production operations contributed $28.9 million in other income, and our oil and gas revenues increased to $37.5 million,
up $27.7 million as compared to the first nine months of 2013. We expect revenues and other income from non-coal-related sources as a percentage of total revenues and other income to increase as a result of the VantaCore and Kaiser-Francis
acquisitions.
The coal markets have continued to be challenged during the first nine months of 2014. While the thermal coal market was
starting to show signs of recovery earlier this year aided by the cold winter and higher natural gas prices, natural gas prices have declined significantly since early in the year, and thermal coal prices have continued to be depressed. We believe
that thermal coal production from our properties in the low-cost Illinois Basin will continue to remain strong in spite of the weak thermal markets. We expect the markets for thermal coal from our other regions to remain weak for the remainder of
2014.
22
We continue to have substantial exposure to metallurgical coal, from which we derived
approximately 39% of our coal revenues and 32% of the related production during the first nine months of 2014. The third quarter 2014 benchmark price for metallurgical coal remains at a multi-year low, and the global metallurgical coal market
continues to suffer from oversupply in addition to reduced demand from China. In response to the difficult market conditions, Alpha Natural Resources has idled three mines in West Virginia, but we expect these mines to continue to sell coal out of
inventory for the remainder of 2014 and accordingly, we do not expect there to be a material adverse impact on our 2014 results as a result of these idlings. We do not anticipate metallurgical coal prices recovering in 2014, and additional
reductions of production of metallurgical coal from our properties may occur in the remainder of 2014 as long as prices remain at current levels. If coal prices continue to remain depressed for an extended period of time, the lessees on some of our
coal properties may close some of their mines causing some of our coal properties to be impaired.
Our trona mining and soda ash refinery
investment performed in line with our expectations during the first nine months of 2014. The international market for soda ash continues to improve, as global production capacity for high-cost synthetic soda ash continues to be reduced, and OCI
Wyomings sales through ANSAC were better than expected. Domestic sales volumes, which are typically sold at higher prices than soda ash sold internationally, have remained relatively stable. The cash we receive from OCI Wyoming is in part
determined by the quarterly distribution declared by OCI Resources LP. Subsequent to the end of the third quarter, OCI Resources LP announced that it would increase its quarterly distribution for the third quarter by 5% over the second quarter to
$0.525 per common unit.
Natural gas and crude oil prices both declined since the second quarter. Natural gas prices have been driven
down by significant U.S. onshore production growth and the resurgent strong pace of seasonal storage injection during the summer. Growth of natural gas production is anticipated to continue, which will factor into price fluctuations as seasonal
injection slows in the winter. In the third quarter 2014, global oil prices have declined as compared to the second quarter 2014. Increased oil supply driven by the robust onshore U.S. development activity coupled with reducing global demand
and a strong U.S. dollar are seen as the main catalysts.
Political, Legal and Regulatory Environment Affecting Our Coal Business
The political, legal and regulatory environment continues to be difficult for the coal industry. The Environmental Protection
Agency (EPA) has used its authority to create significant delays in the issuance of new permits and the modification of existing permits, which has led to substantial delays and increased costs for coal operators. In addition, the
electric utility industry, which is the most significant end-user of domestic coal, is subject to extensive regulation regarding the environmental impact of its power generation activities. In January 2014, EPA published proposed new source
performance standards for greenhouse gas emissions from new fossil fuel-fired electric generating units. The effect of the proposed rules would be to require partial carbon capture and sequestration on any new coal-fired power plants, which may
amount to their effective prohibition. In June 2014, EPA issued proposed regulations on existing fossil fuel-fired power plants (the Clean Power Plan), calling for a nationwide reduction in CO2
emissions of 30% below 2005 levels by 2030. While the timing of implementation of these proposed rules is uncertain, we expect that EPAs proposed regulations for new power plants and the Clean Power Plan will negatively affect the viability of
coal-fired power generation, which will ultimately reduce coal consumption and the production of coal from our properties. Furthermore, EPAs Mercury and Air Toxics (MATS) rule and Cross-State Air Pollution Rule (CSAPR), which have been
recently upheld by U.S. federal courts, are expected to adversely affect coal-fired power plants in the nearer term. Additional recent decisions by U.S. federal courts granting EPA the power to challenge and under certain circumstances retroactively
veto permits further prolongs uncertainties for companies operating with Clean Water Act fill permits and their business partners.
In
addition to government action, private citizens groups have continued to be active in bringing lawsuits against operators and landowners. In 2012 and 2013, several citizen group lawsuits were filed against mine operators for allegedly
violating conditions in their NPDES permits requiring compliance with West Virginias water quality standards. Some of the lawsuits allege violations of water quality standards for selenium, whereas others allege that discharges of conductivity
and sulfate are causing violations of West Virginias narrative water quality standards, which generally prohibit adverse effects to aquatic life. The citizen suit groups seek penalties as well as injunctive relief that would limit future
discharges of selenium, conductivity or sulfate. While it is too early to determine the ultimate resolution of these lawsuits, any rulings requiring operators to reduce their discharges of selenium, conductivity or sulfate could result in large
treatment expenses for our lessees. In 2013, several citizen group lawsuits were filed against landowners alleging ongoing discharges of pollutants, including selenium, from valley fills located at reclaimed mountaintop removal mining sites in West
Virginia. In each case, the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond has been released. While it is too early to predict the final outcome of any of these lawsuits, any final
determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.
23
Recent Acquisitions
We are a growth-oriented company and have closed a number of acquisitions over the last several years. Our most recent acquisitions are briefly
described below.
Kaiser-Francis. On October 5, 2014, we entered into a definitive agreement to acquire non-operated working
interests in oil and gas assets located in the Bakken/Three Forks play from an affiliate of Kaiser-Francis Oil Company for $340 million, subject to customary purchase price adjustments (the Kaiser-Francis acquisition). Upon entering into
the agreement, we paid a deposit of $25 million. The assets include approximately 5,700 net acres in the Sanish Field in Mountrail County, North Dakota and include an estimated average working interest of 15% in approximately 200 wells that are
producing or in various stages of development in addition to the opportunity to participate in future development locations. The assets are all held by production and are operated by Whiting Petroleum Corporation. The acquisition will have an
effective date of October 1, 2014 and is expected to close in November 2014, subject to the satisfaction of customary closing conditions.
VantaCore. On October 1, 2014, we completed the acquisition of VantaCore, a privately held limited partnership specializing in the
construction materials industry, for $205 million in cash and common units, subject to customary post-closing purchase price adjustments. Headquartered in Philadelphia, Pennsylvania, VantaCore operates three hard rock quarries, six sand and gravel
plants, two asphalt plants and a marine terminal. VantaCores current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. We internally estimate that VantaCore controlled approximately 295 million tons
of aggregate reserves as of December 31, 2013.
Sundance. In December 2013, we acquired non-operated working interests in oil
and gas properties in the Williston Basin of North Dakota, including properties producing from the Bakken/Three Forks play, from Sundance Energy, Inc. for $29.4 million, following post-closing purchase price adjustments. The properties, which are
all held by production are located in McKenzie, Mountrail and Dunn counties and are actively being developed.
Abraxas. In August 2013, we acquired non-operated working interests in producing oil and gas properties in the Williston Basin of North
Dakota and Montana, including properties producing from the Bakken/Three Forks play, from Abraxas Petroleum Corporation for $38.0 million, following post-closing purchase price adjustments.
OCI Wyoming. In January 2013, we acquired a non-controlling equity interest in OCI Wyoming, an operator of a trona ore mining
operation and a soda ash refinery in the Green River Basin, Wyoming, from Anadarko Holding Company and its subsidiary, Big Island Trona Company for $292.5 million. The acquisition agreement provides for up to the net present value of $50 million in
additional contingent consideration payable by us should certain performance criteria be met as defined in the purchase and sales agreement in any of 2013, 2014 or 2015. We accrued $15 million as part of the purchase consideration, of which we have
paid $0.5 million in contingent consideration to Anadarko with respect to 2013.
Non-GAAP Financial Measures
Distributable Cash Flow
Under our partnership agreement, we are required to distribute all of our available cash each quarter. Because distributable cash flow is a
significant liquidity metric that is an indicator of our ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to our partners, we view it as the most important measure of our success
as a company. Distributable cash flow is also the quantitative standard used in the investment community with respect to publicly traded partnerships.
Our distributable cash flow represents cash flow from operations, proceeds from sale of assets, returns on direct financing lease and
contractual override and distributions from unconsolidated affiliates. Although distributable cash flow is a non-GAAP financial measure, we believe it is a useful adjunct to net cash provided by operating activities under GAAP.
Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. Distributable cash flow may not be calculated the same for
us as for other companies.
24
Reconciliation of Net cash provided by operating activities to Distributable
cash flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands)
(unaudited) |
|
Net cash provided by operating activities |
|
$ |
57,458 |
|
|
$ |
65,866 |
|
|
$ |
157,096 |
|
|
$ |
189,515 |
|
Return on direct financing lease and contractual override |
|
|
310 |
|
|
|
286 |
|
|
|
910 |
|
|
|
841 |
|
Distributions from unconsolidated affiliates |
|
|
|
|
|
|
38,056 |
|
|
|
3,633 |
|
|
|
48,833 |
|
Proceeds from sale of assets |
|
|
5 |
|
|
|
405 |
|
|
|
5 |
|
|
|
559 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow |
|
$ |
57,773 |
|
|
$ |
104,613 |
|
|
$ |
161,644 |
|
|
$ |
239,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
EBITDA is a non-GAAP financial measure that we define as earnings before interest, taxes, depreciation, depletion and amortization and asset
impairment, including interest, taxes, depreciation and amortization relating to OCI Wyoming. EBITDA, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance
calculated in accordance with GAAP. EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow
statement data prepared in accordance with GAAP. EBITDA provides no information regarding a companys capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax positions. EBITDA does not represent
funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital and other commitments and obligations. We believe EBITDA is useful in evaluating our financial performance because this
measure is widely used by analysts and investors for comparative purposes. EBITDA is a financial measure widely used by investors in the high-yield bond market. There are significant limitations to using EBITDA as a measure of performance, including
the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDA
reported by different companies.
Reconciliation of Net income to EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Month Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands)
(unaudited) |
|
Net income |
|
$ |
36,173 |
|
|
$ |
36,126 |
|
|
$ |
100,185 |
|
|
$ |
125,097 |
|
Add depreciation, depletion and amortization |
|
|
18,621 |
|
|
|
17,852 |
|
|
|
49,618 |
|
|
|
50,025 |
|
Add asset impairments |
|
|
|
|
|
|
|
|
|
|
5,624 |
|
|
|
734 |
|
Add interest expense, gross |
|
|
18,862 |
|
|
|
15,516 |
|
|
|
57,759 |
|
|
|
44,619 |
|
Add depreciation and amortization, interest and taxes relating to OCI Wyoming |
|
|
4,628 |
|
|
|
3,366 |
|
|
|
13,996 |
|
|
|
9,068 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
|
$ |
78,284 |
|
|
$ |
72,860 |
|
|
$ |
227,182 |
|
|
$ |
229,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA presented in the table above differs from the EBITDDA definitions contained in Opcos debt
agreement covenants. In calculating EBITDDA for purposes of Opcos debt covenant compliance, pro forma effect may be given to acquisitions and dispositions made during the relevant period. See Liquidity and Capital
ResourcesContractual Obligations and Commercial CommitmentsOpco Debt for a description of Opcos debt agreements.
Results of Operations
As disclosed in Note 2. Significant Accounting Policies Update, amounts relating to coal
royalties, processing fees, transportation fees, minimums recognized as revenue, override royalties and other for the three and nine months ended September 30, 2013 have been reclassified into a single line item Coal related
revenues on the Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2014. Similarly, amounts relating to 2013 aggregate royalties, processing fees, minimums recognized as revenue, override
royalties and other have been reclassified into a single line item Aggregate related revenues on the Consolidated Statements of Comprehensive Income. Accordingly, we have revised our comparative discussions below to make corresponding
changes.
25
Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013
Coal Related Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Increase (Decrease) |
|
|
Percentage Change |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
(In thousands, except percent and per ton data)
(Unaudited) |
|
Regional Statistics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal royalty production (tons) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern |
|
|
2,060 |
|
|
|
2,779 |
|
|
|
(719 |
) |
|
|
(26 |
)% |
Central |
|
|
5,432 |
|
|
|
5,116 |
|
|
|
316 |
|
|
|
6 |
% |
Southern |
|
|
1,017 |
|
|
|
921 |
|
|
|
96 |
|
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Appalachia |
|
|
8,509 |
|
|
|
8,816 |
|
|
|
(307 |
) |
|
|
(3 |
)% |
Illinois Basin |
|
|
3,526 |
|
|
|
3,635 |
|
|
|
(109 |
) |
|
|
(3 |
)% |
Northern Powder River Basin |
|
|
1,054 |
|
|
|
735 |
|
|
|
319 |
|
|
|
43 |
% |
Gulf Coast |
|
|
281 |
|
|
|
290 |
|
|
|
(9 |
) |
|
|
(3 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
13,370 |
|
|
|
13,476 |
|
|
|
(106 |
) |
|
|
(1 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average coal royalty revenue per ton |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern |
|
$ |
0.90 |
|
|
$ |
1.04 |
|
|
$ |
(0.14 |
) |
|
|
(13 |
)% |
Central |
|
|
4.69 |
|
|
|
4.94 |
|
|
|
(0.25 |
) |
|
|
(5 |
)% |
Southern |
|
|
5.04 |
|
|
|
6.05 |
|
|
|
(1.01 |
) |
|
|
(17 |
)% |
Total Appalachia |
|
|
3.81 |
|
|
|
3.83 |
|
|
|
(0.02 |
) |
|
|
(1 |
)% |
Illinois Basin |
|
|
4.08 |
|
|
|
4.23 |
|
|
|
(0.15 |
) |
|
|
(4 |
)% |
Northern Powder River Basin |
|
|
2.91 |
|
|
|
3.10 |
|
|
|
(0.19 |
) |
|
|
(6 |
)% |
Gulf Coast |
|
|
3.40 |
|
|
|
3.24 |
|
|
|
0.16 |
|
|
|
5 |
% |
Combined average gross royalty per ton |
|
$ |
3.80 |
|
|
$ |
3.88 |
|
|
$ |
(0.08 |
) |
|
|
(2 |
)% |
Coal royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern |
|
$ |
1,844 |
|
|
$ |
2,882 |
|
|
$ |
(1,038 |
) |
|
|
(36 |
)% |
Central |
|
|
25,470 |
|
|
|
25,270 |
|
|
|
200 |
|
|
|
1 |
% |
Southern |
|
|
5,130 |
|
|
|
5,571 |
|
|
|
(441 |
) |
|
|
(8 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Appalachia |
|
|
32,444 |
|
|
|
33,723 |
|
|
|
(1,279 |
) |
|
|
(4 |
)% |
Illinois Basin |
|
|
14,403 |
|
|
|
15,364 |
|
|
|
(961 |
) |
|
|
(6 |
)% |
Northern Powder River Basin |
|
|
3,069 |
|
|
|
2,279 |
|
|
|
790 |
|
|
|
35 |
% |
Gulf Coast |
|
|
954 |
|
|
|
939 |
|
|
|
15 |
|
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
50,870 |
|
|
$ |
52,305 |
|
|
$ |
(1,435 |
) |
|
|
(3 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other coal related revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Override revenue |
|
$ |
771 |
|
|
$ |
2,269 |
|
|
$ |
(1,498 |
) |
|
|
(66 |
)% |
Transportation and processing fees |
|
|
5,589 |
|
|
|
6,005 |
|
|
|
(416 |
) |
|
|
(7 |
)% |
Minimums recognized as revenue |
|
|
1,396 |
|
|
|
626 |
|
|
|
770 |
|
|
|
123 |
% |
Reserve swap |
|
|
5,690 |
|
|
|
|
|
|
|
5,690 |
|
|
|
|
|
Wheelage |
|
|
877 |
|
|
|
799 |
|
|
|
78 |
|
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
14,323 |
|
|
$ |
9,699 |
|
|
$ |
4,624 |
|
|
|
48 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total coal related revenues |
|
$ |
65,193 |
|
|
$ |
62,004 |
|
|
$ |
3,189 |
|
|
|
5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total coal related revenues. Total coal related revenues comprised approximately 71% and
75% of our total revenues and other income for the three month periods ended September 30, 2014 and 2013, respectively. The following is a discussion of the major categories of coal related revenue:
Coal royalty revenues and production. Coal royalty revenues comprised approximately 56% and 64% of our total revenues and
other income for the three month periods ended September 30, 2014 and 2013, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:
Appalachia. Coal royalty revenues decreased $1.3 million or 4% in the three-month period ended September 30, 2014 compared to the
same period of 2013, while production decreased 307,000 tons or 3%.
26
Production from our properties in the Central Appalachian region increased by 6%. This increase
was primarily due to the net positive effect of more of our lessees having a greater proportion of their mining on our property. In addition, pricing realized by our lessees for both thermal and metallurgical coal in Central Appalachia is generally
below the levels received in the same quarter in 2013, causing a smaller percentage increase in coal royalty revenues compared to the increase in production.
The Southern Appalachian region also had increased production but coal royalty revenues were lower due to our lessees generally having lower
sales prices for both thermal and metallurgical coal.
With respect to Northern Appalachia, during the quarter ended September 30,
2014 there was a decrease in coal royalty revenues and production. These decreases were primarily due to the longwall mining unit of one lessee moving off of our property to adjacent property in the normal course of its mining plan.
Illinois Basin. Coal royalty revenues for the three months ended September 30, 2014 decreased 6% when compared to the same period
in 2013, while production was nearly constant. Our Williamson and Hillsboro properties in Illinois had lower production as did one of our properties in Indiana. These decreases were partially offset by higher production at the Macoupin property
where an additional mining unit was added and increased revenue from a coal reserve acquisition completed in June 2014.
Northern
Powder River Basin. Coal royalty revenues and production increased on our Western Energy property due to the normal variations that occur due to the checkerboard nature of ownership. The lessee reported a slightly lower sales price for the three
months ending September 30, 2014, reducing the royalty revenue per ton.
Gulf Coast. Coal royalty revenue increased but
production for the three months ended September 30, 2014 decreased compared to the same period in 2013. The mix of production was greater from leases with higher revenue per ton, resulting in the revenue increase.
Other coal related revenues. Other coal related revenues for the three months ended September 30, 2014 increased 48% compared to
the same period in 2013. The following is a discussion of the revenues derived from each of the major sources of other coal-related revenue:
Override revenues for the three months ended September 30, 2014 decreased by 66% compared to the same period in 2013 primarily due to one
lessee moving its mining operations from an area on which we receive an overriding royalty onto property on which we receive coal royalty revenues, another lessee exhausting the reserves subject to the override and other lessees mining less on the
area subject to our overriding royalty.
Transportation and processing fees decreased by $0.4 million or 7%, for the three months ended
September 30, 2014, when compared to the same period in 2013. The decrease is primarily due to lower tonnage being put through all our facilities except Macoupin, the temporary idling of two processing facilities in response to market
conditions, and timing of tonnage moving across our transportation assets.
Minimums recognized as revenue increased $0.8 million or 123%
for the three months ended September 30, 2014 when compared to the same period in 2013, primarily due to the recoupment period on two of our lessees previously paid annual minimums expiring.
During the three months ended September 30, 2014 we also recognized revenue of $5.7 million related to a reserve swap completed in the
quarter. We did not have a similar transaction in the same period in 2013.
Wheelage revenue increased by 10% for the three months ended
September 30, 2014 compared to the same period in 2013. This increase was due to the normal fluctuations of tonnage that are subject to wheelage charges.
27
Aggregates and Industrial Minerals Revenues, and Other Related Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Increase (Decrease) |
|
|
Percentage Change |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
(In thousands, except percent and per ton data)
(Unaudited) |
|
Aggregates royalty revenues and production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tonnage |
|
|
702 |
|
|
|
1,767 |
|
|
|
(1,065 |
) |
|
|
(60 |
)% |
Aggregates royalty per ton |
|
$ |
0.79 |
|
|
$ |
1.13 |
|
|
$ |
(0.34 |
) |
|
|
(30 |
)% |
Total aggregates royalty revenues |
|
$ |
553 |
|
|
$ |
1,996 |
|
|
$ |
(1,443 |
) |
|
|
(72 |
)% |
|
|
|
|
|
Other aggregates related revenues |
|
$ |
2,102 |
|
|
$ |
1,793 |
|
|
$ |
309 |
|
|
|
17 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregates related revenues |
|
$ |
2,655 |
|
|
$ |
3,789 |
|
|
$ |
(1,134 |
) |
|
|
(30 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity and other unconsolidated investment earnings |
|
$ |
9,685 |
|
|
$ |
7,238 |
|
|
$ |
2,447 |
|
|
|
34 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregates and industrial minerals revenues, and other related income |
|
$ |
12,340 |
|
|
$ |
11,027 |
|
|
$ |
1,313 |
|
|
|
12 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregates and industrial minerals revenues, and other related income. Total aggregates and
industrial minerals revenues, and other related income represented approximately 13% of our total revenues and other income for both of the three month periods ended September 30, 2014 and 2013, respectively. The following is a discussion of
the major categories of these revenues:
Aggregates royalty revenues decreased 72% and production decreased 60% for the quarter
ended September 30, 2014 and while average royalty per ton decreased 30%. This decrease is primarily due to one of our lessees moving from property which we receive royalty revenue from to property on which we receive override revenue.
Other aggregates related revenues were up $0.3 million or 17% compared to last year due to an override revenues increasing on our Washington
aggregates property due to a lessee moving from our owned property to an area subject to an override. Override revenues also increased on our frac sand properties by $0.9 million or 136% over the third quarter of 2013.
Equity and other unconsolidated investment earnings. Income from our investment in the OCI Wyoming trona mining and soda ash production
business was $9.7 million for the quarter ended September 30, 2014, and we received $10.3 million in cash during the quarter. For the same period in 2013, we recorded equity income of $7.2 million and received $46.0 million in cash, which
included a one-time special distribution of $44.8 million. This represents an increase in equity income of 34% due to improved earnings from OCI Wyoming in 2014 over 2013.
28
Oil and Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Increase (Decrease) |
|
|
Percentage Change |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
(In thousands, except percent and per unit data)
(Unaudited) |
|
Williston Basin non-operated working interests: |
|
|
|
|
|
|
|
|
|
|
|
|
Production volumes |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
77 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Natural gas (Mcf) |
|
|
90 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
NGL (MBoe) |
|
|
8 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Average sales price per unit |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) |
|
$ |
84.65 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Natural gas (Mcf) |
|
$ |
5.11 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
NGL (Boe) |
|
$ |
41.00 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
6,518 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Natural gas |
|
|
460 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
NGL |
|
|
328 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
7,306 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Other oil and gas revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Royalty and overriding revenues |
|
$ |
2,295 |
|
|
$ |
3,886 |
|
|
$ |
(1,591 |
) |
|
|
(41 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas revenues |
|
$ |
9,601 |
|
|
$ |
3,886 |
|
|
$ |
5,715 |
|
|
|
147 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues increased $5.7 million for the current quarter when compared to the same quarter in 2013.
The increase in revenues is due to revenues from our Williston Basin non-operated working interest properties which were acquired during the second half of 2013.
29
Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Coal Related Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
Increase (Decrease) |
|
|
Percentage Change |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
(In thousands, except percent and per ton data)
(Unaudited) |
|
Regional Statistics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal royalty production (tons) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern |
|
|
6,537 |
|
|
|
10,051 |
|
|
|
(3,514 |
) |
|
|
(35 |
)% |
Central |
|
|
15,096 |
|
|
|
16,062 |
|
|
|
(966 |
) |
|
|
(6 |
)% |
Southern |
|
|
2,950 |
|
|
|
3,188 |
|
|
|
(238 |
) |
|
|
(7 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Appalachia |
|
|
24,583 |
|
|
|
29,301 |
|
|
|
(4,718 |
) |
|
|
(16 |
)% |
Illinois Basin |
|
|
10,064 |
|
|
|
9,541 |
|
|
|
523 |
|
|
|
5 |
% |
Northern Powder River Basin |
|
|
2,106 |
|
|
|
2,499 |
|
|
|
(393 |
) |
|
|
(16 |
)% |
Gulf Coast |
|
|
720 |
|
|
|
862 |
|
|
|
(142 |
) |
|
|
(16 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
37,473 |
|
|
|
42,203 |
|
|
|
(4,730 |
) |
|
|
(11 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average coal royalty revenue per ton |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern |
|
$ |
0.91 |
|
|
$ |
1.19 |
|
|
$ |
(0.28 |
) |
|
|
(24 |
)% |
Central |
|
|
4.59 |
|
|
|
5.10 |
|
|
|
(0.51 |
) |
|
|
(10 |
)% |
Southern |
|
|
5.24 |
|
|
|
6.47 |
|
|
|
(1.23 |
) |
|
|
(19 |
)% |
Total Appalachia |
|
|
3.69 |
|
|
|
3.91 |
|
|
|
(0.22 |
) |
|
|
(6 |
)% |
Illinois Basin |
|
|
4.07 |
|
|
|
4.28 |
|
|
|
(0.21 |
) |
|
|
(5 |
)% |
Northern Powder River Basin |
|
|
2.87 |
|
|
|
2.68 |
|
|
|
0.19 |
|
|
|
7 |
% |
Gulf Coast |
|
|
3.43 |
|
|
|
3.36 |
|
|
|
0.07 |
|
|
|
2 |
% |
Combined average gross royalty per ton |
|
$ |
3.74 |
|
|
$ |
3.91 |
|
|
$ |
(0.17 |
) |
|
|
(4 |
)% |
Coal royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern |
|
$ |
5,941 |
|
|
$ |
12,008 |
|
|
$ |
(6,067 |
) |
|
|
(51 |
)% |
Central |
|
|
69,289 |
|
|
|
81,861 |
|
|
|
(12,572 |
) |
|
|
(15 |
)% |
Southern |
|
|
15,469 |
|
|
|
20,623 |
|
|
|
(5,154 |
) |
|
|
(25 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Appalachia |
|
|
90,699 |
|
|
|
114,492 |
|
|
|
(23,793 |
) |
|
|
(21 |
)% |
Illinois Basin |
|
|
40,956 |
|
|
|
40,864 |
|
|
|
92 |
|
|
|
|
|
Northern Powder River Basin |
|
|
6,041 |
|
|
|
6,703 |
|
|
|
(662 |
) |
|
|
(10 |
)% |
Gulf Coast |
|
|
2,473 |
|
|
|
2,898 |
|
|
|
(425 |
) |
|
|
(15 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
140,169 |
|
|
$ |
164,957 |
|
|
$ |
(24,788 |
) |
|
|
(15 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other coal related revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Override revenue |
|
$ |
3,516 |
|
|
$ |
8,713 |
|
|
$ |
(5,197 |
) |
|
|
(60 |
)% |
Transportation and processing fees |
|
|
16,682 |
|
|
|
17,010 |
|
|
|
(328 |
) |
|
|
(2 |
)% |
Minimums recognized as revenue |
|
|
4,204 |
|
|
|
5,613 |
|
|
|
(1,409 |
) |
|
|
(25 |
)% |
Reserve swap |
|
|
5,690 |
|
|
|
8,149 |
|
|
|
(2,459 |
) |
|
|
(30 |
)% |
Wheelage |
|
|
2,666 |
|
|
|
2,794 |
|
|
|
(128 |
) |
|
|
(5 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
32,758 |
|
|
$ |
42,279 |
|
|
$ |
(9,521 |
) |
|
|
(23 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total coal related revenues |
|
$ |
172,927 |
|
|
$ |
207,236 |
|
|
$ |
(34,309 |
) |
|
|
(17 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total coal related revenues. Total coal related revenues comprised approximately 66% and
79% of our total revenues and other income for the nine month periods ended September 30, 2014 and 2013, respectively. The following is a discussion of the major categories of coal related revenue:
Coal royalty revenues and production. Coal royalty revenues comprised approximately 53% and 63% of our total revenues and
other income for the nine month periods ended September 30, 2014 and 2013, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:
Appalachia. Coal royalty revenues decreased $23.8 million or 21% in the nine-month period ended September 30, 2014 compared to the
same period of 2013, while production decreased 4.7 million tons or 16%.
30
Production from our properties in the Central Appalachian region declined by 6% due to a
combination of the idling of mining units or mines, lower sales volumes from mines on our property and some mining units moving off of our property to adjacent properties in the normal course of their mine plans. In addition, pricing realized by our
lessees for both thermal and metallurgical coal in Central Appalachia is generally below the levels of the same period in 2013, causing a higher percentage decrease in coal royalty revenues compared to the decrease in production.
The Southern Appalachian region also had decreased production and coal royalty revenues, primarily due to one of our lessees curtailing
production during the sale of its operations and the successor lessee being slower in increasing production after the acquisition and the timing of sales by some other lessees. In addition prices from the metallurgical sales from our properties were
lower than the same period in 2013, creating a higher percentage decrease in coal royalty revenue compared to the decrease in coal production.
With respect to Northern Appalachia, during the nine months ended September 30, 2014 there was also a decrease in coal royalty revenue
and production. These decreases were primarily due to one lessee moving its longwall mining unit to adjacent property in the normal course of its mine plan and one lessee moving mining units to adjacent property in the normal course of its mine
plan. This tonnage decrease was partially offset by another lessee, from which we receive a very low royalty per ton, having a greater proportion of its production on our property. Our revenue per ton in the region was also lower primarily due to
this low royalty per ton lease being a larger proportion of production in the region.
Illinois Basin. Coal royalty revenues for
the nine months ended September 30, 2014 increased $0.1 million when compared to the same period in 2013, and production increased by 5%. Increased production from our Williamson, Hillsboro and Macoupin properties was partially offset by lower
sales a property in Indiana where a lessee had a greater proportion of production from adjacent properties. We also received tonnage and revenue from a coal reserve acquisition completed in June 2014, which contributed to the higher tonnage and
sales. We had a greater proportion of production from leases with lower per ton royalties which contributed to the smaller revenue increase.
Northern Powder River Basin. Coal royalty revenues and production decreased on our Western Energy property due to the normal variations
that occur due to the checkerboard nature of ownership.
Gulf Coast. Coal royalty revenue and production for the nine months ended
September 30, 2014 decreased compared to the same period in 2013 due to lower production by our lessees.
Other coal related
revenues. Other coal related revenues for the nine months ended September 30, 2014 decreased 23% compared to the same period in 2013. The following is a discussion of the revenues derived from each of the major sources of other coal-related
revenue:
Override revenue for the nine months ended September 30, 2014 decreased by 60% compared to the same period in 2013 due to
one lessee moving its mining operations from an area on which we receive an overriding royalty onto property on which we receive coal royalty revenue, one lessee exhausting the reserves subject to the override and other lessees mining fewer tons on
properties on which we receive an overriding royalty.
Transportation and processing fees decreased 2% for the nine months of 2014, when
compared to the same period in 2013. The decrease in revenue was due to lower tonnage put through our all our facilities except Macoupin and the temporary idling of two processing facilities in response to market conditions.
Minimums recognized as revenue decreased $1.4 million or 25% for the nine months ended September 30, 2014 when compared to the same
period in 2013, primarily due to the recoupment period on Foresight Energys Macoupin mine expiring in 2013 for minimums paid in 2009. Minimums for that lease paid after 2009 have longer recoupment periods. This was partially offset by two of
our lessees previously paid annual minimums expiring and adjustment to the recoupable balance of another lessee.
We had reserve
swaps in the corresponding periods in both 2014 and 2013. The revenue associated with the 2013 reserve swap was larger than that in 2014.
Wheelage revenue decreased by 5% for the nine months ended September 30, 2014 compared to the same period in 2013. This slight decrease
was due to the normal fluctuations of tonnage that are subject to wheelage charges.
31
Aggregates and Industrial Minerals Revenues, and Other Related Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
Increase (Decrease) |
|
|
Percentage Change |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
(In thousands, except percent and per ton data)
(Unaudited) |
|
Aggregates royalty revenues and production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tonnage |
|
|
2,844 |
|
|
|
4,513 |
|
|
|
(1,669 |
) |
|
|
(37 |
)% |
Aggregates royalty per ton |
|
$ |
0.94 |
|
|
$ |
1.17 |
|
|
$ |
(0.23 |
) |
|
|
(20 |
)% |
Total aggregates royalty revenues |
|
$ |
2,678 |
|
|
$ |
5,299 |
|
|
$ |
(2,621 |
) |
|
|
(49 |
)% |
|
|
|
|
|
Other aggregates related revenues |
|
$ |
6,936 |
|
|
$ |
4,363 |
|
|
$ |
2,573 |
|
|
|
59 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregates related revenues |
|
$ |
9,614 |
|
|
$ |
9,662 |
|
|
$ |
(48 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity and other unconsolidated investment earnings |
|
$ |
28,865 |
|
|
$ |
22,168 |
|
|
$ |
6,697 |
|
|
|
30 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregates and industrial minerals revenues, and other related income |
|
$ |
38,479 |
|
|
$ |
31,830 |
|
|
$ |
6,649 |
|
|
|
21 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregates and industrial minerals revenues, and other related income. Total aggregates and
industrial minerals revenues, and other related income represented approximately 15% and 12% of our total revenues and other income for the nine month periods ended September 30, 2014 and 2013, respectively. The following is a discussion of the
major categories of these revenues:
Aggregates royalty revenues decreased 49% and production decreased 37% for the nine months
ended September 30, 2014, while average royalty per ton decreased 20%. These decreases were primarily due to one lessee moving from property on which we owned the reserves, to property on which we receive an overriding royalty.
Other aggregates related revenues were up $2.6 million or 59% compared to last year due to a lessee relinquishing their recoupments rights on
previously paid minimums in 2014 and override revenues increasing on our Washington aggregates property due to a lessee moving from our owned property to an area subject to an override. Override revenues also increased on our frac sand properties by
$1.3 million or 58% over the first nine months of 2013.
Equity and other unconsolidated investment earnings. Income from our
investment in the OCI Wyoming trona mining and soda ash production business was $28.9 million for the nine months ended September 30, 2014 and we received $35.9 million in cash during the first nine months of 2014. For the same period in 2013,
we recorded equity income of $22.2 million and received $72.9 million in cash. This represents an increase in equity income of 30% due to the first quarter of 2014 reflecting a full quarter of revenues as well as improved earnings from OCI Wyoming
in 2014 over 2013.
32
Oil and Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
Increase (Decrease) |
|
|
Percentage Change |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
(In thousands, except percent and per unit data)
(Unaudited) |
|
Williston Basin non-operated working interests: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
284 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Natural gas (Mcf) |
|
|
202 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
NGL (MBoe) |
|
|
20 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Average sales price per unit |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) |
|
$ |
92.82 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Natural gas (Mcf) |
|
$ |
6.45 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
NGL (Boe) |
|
$ |
45.55 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
26,360 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Natural gas |
|
|
1,303 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
NGL |
|
|
911 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
28,574 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Other oil and gas revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty and overriding revenues |
|
$ |
8,907 |
|
|
$ |
9,742 |
|
|
$ |
(835 |
) |
|
|
(9 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas revenues |
|
$ |
37,481 |
|
|
$ |
9,742 |
|
|
$ |
27,739 |
|
|
|
285 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues increased $27.7 million for the nine months ended September 30, 2014 when compared
to the same period in 2013. The increase is primarily due to revenues from our Williston Basin non-operated working interest properties which were acquired during the second half of 2013.
Other Operating Results
In addition to coal related revenues, aggregates and industrial minerals revenues and other revenues and oil and gas revenues, we generated
approximately 5% and 6% of our total revenues and other income from other sources for the three and nine months ended September 30, 2014 and 2013. Other sources of revenues primarily include: reimbursements of property taxes from our lessees,
rentals, metal revenue and timber royalties.
Operating costs and expenses. The following is a discussion of our operating costs
and expenses for the three and nine months ended September 30, 2014 as compared to the same periods of 2013:
|
|
|
Depreciation, depletion and amortization expenses were up $0.8 million for the three months ended September 30, 2014 when compared to the same period for 2013 partially due to higher depletion on our Williamson
property affected by the reserve swap during third quarter of 2014. On a year to date comparison, depletion is down $0.4 million for 2014 when compared to the same period of 2013 on lower coal production offset by increased oil and gas depletion for
our non-operated working interests that were acquired during the second half of 2013. |
|
|
|
General and administrative expenses was virtually flat for the third quarter of 2014 when compared to the same quarter in 2013, while for the nine month periods ending September 30, 2014 and 2013 expense decreased
$5.2 million. The change in general and administrative expense is primarily due to a decrease in long term incentive plan expense due to the fluctuation in unit price. |
|
|
|
Operating expenses increased for the 2014 period due to a $2.5 million accrued liability relating to a payment due to a royalty owner on one of NRPs properties. |
Interest expense. Interest expense increased approximately $3.3 million and $13.1 million for the three and nine months ended
September 30, 2014 over the same periods in 2013. The increase reflects the issuance of NRPs 9.125% senior notes issued in September 2013.
33
Liquidity and Capital Resources
Cash Flows and Capital Expenditures
Generally, we satisfy our working capital requirements with cash generated from operations. We finance our property acquisitions with available
cash, borrowings under our revolving credit facilities, and the issuance of senior notes and additional common units. While our ability to satisfy our debt service obligations and pay distributions to our unitholders depends in large part on our
future operating performance, our ability to make acquisitions will depend on prevailing economic conditions in the financial markets as well as the coal, oil and gas and aggregates/industrial minerals industries and other factors, some of which are
beyond our control. For a more complete discussion of factors that will affect cash flow we generate from operations, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2013 and Item
1A. Risk Factors in this Quarterly Report on Form 10-Q. Our capital expenditures, other than for acquisitions, have historically been minimal. However, we incur capital expenditures and operating expenses associated with the non-operated
working interests in oil and gas assets. We finance those capital expenditures through a combination of cash flow from operations and borrowings under the NRP Oil and Gas revolving credit facility.
Opcos revolving credit facility does not mature until August 2016 and, as of September 30, 2014, Opco had $293 million in
available capacity under the facility. As of September 30, 2014, NRP Oil and Gas had $18.0 million available for borrowing under its revolving credit facility. In connection with the closing of the Kaiser-Francis acquisition, NRP Oil and
Gass revolving credit facility will be amended, and the borrowing base thereunder is expected to be increased to $137 million. We expect to borrow up to $120 million thereunder to fund a portion of the purchase price of that acquisition. We
typically access the capital markets to refinance amounts outstanding under our revolving credit facilities as we approach the limits under those facilities, the timing of which depends on the pace and size of our acquisition program and development
capital expenditures associated with our oil and gas business.
In addition to the amounts available under our revolving credit
facilities, we had $78.1 million in cash at September 30, 2014. As of the date of this report, NRP has sold 1,539,314 common units through its at-the-market offering (ATM) program during 2014 for approximately $24.8
million in gross proceeds, excluding our general partners capital contribution to maintain its 2% general partner interest in us. During the first nine months of 2014, we repaid $56.2 million of principal on Opcos senior notes and
utility local improvement obligation and repaid $13.0 million on Opcos revolving credit facility, thereby reducing our total outstanding debt by $69.2 million.
Subsequent to the end of the third quarter, we issued approximately 2.4 million common units to fund a portion of the purchase price of
the VantaCore acquisition. We also issued 8.5 million common units in a public offering of common units and sold an additional $125 million aggregate principal amount of our 9.125% senior notes due 2018 in a private offering. We intend to use
the net proceeds from these offerings, which totaled $222.5 million (including our general partners capital contribution to maintain its 2% general partner interest in us in connection with the common unit offering), to fund a portion of the
purchase price of the Kaiser-Francis acquisition.
We believe that the combination of our capacity under our revolving credit facilities
and our cash on hand gives us enough liquidity to meet our current financial needs. Other than $81 million in principal repayments due on Opcos senior notes each year for the next several years, we do not have any debt maturing until
2016. As of September 30, 2014, our debt covenant ratios are in compliance for both revolving credit facilities, Opcos term loan facility and Opcos outstanding senior notes. For a more complete discussion of factors that will affect
our liquidity, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2013 and Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.
Net cash provided by operating activities for the nine months ended September 30, 2014 and 2013 was $157.1 million and $189.5 million,
respectively. The majority of our cash provided by operating activities is generated from coal related royalty revenues, our equity interest in OCI Wyoming and beginning in 2014, oil and gas revenues.
Net cash used in investing activities for the nine months ended September 30, 2014 was $9.7 million primarily for additional capital
expenditures relating to our 2013 acquisitions of non-operated working interests in producing oil and gas properties as well as a $5 million acquisition of coal reserves in the Illinois Basin offset by a purchase price adjustment of $4.3 million on
one of our oil and gas acquisitions and a one-time tax distribution from OCI Wyoming of $3.6 million. Net cash used in investing activities for the nine months ended September 30, 2013 was $281.1 million. Substantially all of our 2013 investing
activities consisted of the acquisition of the interest in OCI Wyoming, see Note 4. Equity and Other Investments.
Net cash
used in financing activities for the nine months ended September 30, 2014 was $161.8 million. During the first nine months of 2014, we had net proceeds from loans of $2.0 million, net proceeds from equity transactions of $24.2 million, and a
capital contribution from our general partner of $0.5 million. These proceeds were offset by loan payments of $69.2 million and distributions
34
to partners of $119.3 million. During the same period for 2013, net cash provided by financing activities was $41.9 million, which included net proceeds from loans of $547.0 million, net proceeds
from equity transactions of $74.9 million, and a capital contribution from our general partner of $1.5 million. These proceeds were offset by loan repayments of $386.2 million, debt issuance costs of $9.1 million, and distributions to partners of
$186.3 million.
Contractual Obligations and Commercial Commitments
NRP Debt
Senior
Notes. In September 2013, NRP and NRP Finance as co-issuer completed a private placement of $300 million principal amount of 9.125% Senior Notes due 2018. The notes were offered and sold to qualified institutional buyers pursuant to
Rule 144A under the Securities Act of 1933, as amended, and to persons outside the United States pursuant to Regulation S under the Securities Act. The Notes were issued pursuant to an indenture, dated September 18, 2013, among NRP, NRP
Finance Corporation and Wells Fargo Bank, National Association, as trustee. The notes bear interest at a rate of 9.125% per year, payable semiannually in arrears on April 1 and October 1 of each year. The notes will mature on
October 1, 2018.
In October 2014, NRP and NRP Finance issued an additional $125 million in aggregate principal amount of the 9.125%
Senior Notes due 2018. The notes were issued pursuant to the existing indenture and constitute the same series of securities as the existing 9.125% senior notes due 2018 issued in September 2013. In the offering, $105 million in aggregate principal
amount of the notes were sold in a private placement to the initial purchasers thereof to be offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act, and to persons outside the United States pursuant to
Regulation S under the Securities Act. The remaining $20 million in aggregate principal amount of the Notes were sold in a separate private placement to Cline Trust Company, LLC. The net proceeds of approximately $122.1 million from this offering
will be used to fund a portion of the purchase price of the Kaiser-Francis acquisition.
The notes are the senior unsecured obligations of
NRP and NRP Finance. The notes rank equal in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance and senior in right of payment to any subordinated debt of NRP and NRP Finance. The notes are effectively
subordinated in right of payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and will be structurally subordinated in right of payment to all existing and future debt and
other liabilities of NRPs subsidiaries, including Opcos revolving credit facility and term loan facility, each series of Opcos existing senior notes, and NRP Oil and Gass revolving credit facility. None of NRPs
subsidiaries guarantee the notes.
NRP and NRP Finance have the option to redeem the notes, in whole or in part, at any time on or after
April 1, 2016, at the redemption prices (expressed as percentages of principal amount) of 106.844% for the six-month period beginning on April 1, 2016, 104.563% for the twelve-month period beginning on October 1, 2016 and 100.000%
beginning on October 1, 2017 and at any time thereafter, together with any accrued and unpaid interest to the date of redemption. In addition, before April 1, 2016, NRP and NRP Finance may redeem all or any part of the notes at a
redemption price equal to the sum of the principal amount thereof, 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 for the senior notes contains covenants that limit the ability of NRP and
certain of its subsidiaries to incur or guarantee additional indebtedness. Under the indenture, NRP 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 and certain of its subsidiaries to incur additional indebtedness is further limited in the event the amount of
indebtedness of NRP and its subsidiaries that is senior to NRPs unsecured indebtedness exceeds certain thresholds. The indenture contains additional covenants that, among other things, limit NRPs ability and the ability of certain of its
subsidiaries to declare or pay any dividend or distribution on, purchase or redeem units or purchase or redeem subordinated debt; make investments; create certain liens; enter into agreements that restrict distributions or other payments from
NRPs restricted subsidiaries as defined in the indenture to NRP; sell assets; consolidate, merge or transfer all or substantially all of the assets of NRP and its restricted subsidiaries; engage in transactions with affiliates; create
unrestricted subsidiaries; and enter into certain sale and leaseback transactions.
35
Opco Debt
As of September 30, 2014, Opcos debt consisted of:
|
|
|
$7.0 million drawn under the floating rate revolving credit facility, due August 2016; |
|
|
|
$99.0 million floating rate term loan, due January 2016; |
|
|
|
$18.5 million of 4.91% senior notes due 2018; |
|
|
|
$107.1 million of 8.38% senior notes due 2019; |
|
|
|
$46.2 million of 5.05% senior notes due 2020; |
|
|
|
$1.3 million of 5.31% utility local improvement obligation due 2021; |
|
|
|
$24.3 million of 5.55% senior notes due 2023; |
|
|
|
$75.0 million of 4.73% senior notes due 2023; |
|
|
|
$150.0 million of 5.82% senior notes due 2024; |
|
|
|
$45.5 million of 8.92% senior notes due 2024; |
|
|
|
$175.0 million of 5.03% senior notes due 2026; and |
|
|
|
$50.0 million of 5.18% senior notes due 2026. |
Senior Notes. Opco issued the senior
notes listed below under a note purchase agreement as supplemented from time to time. The senior notes are unsecured but are guaranteed by Opcos subsidiaries. Opco may prepay the senior notes at any time together with a make-whole amount (as
defined in the note purchase agreement). If any event of default exists under the note purchase agreement, the noteholders will be able to accelerate the maturity of the senior notes and exercise other rights and remedies.
The senior note purchase agreement contains 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 to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0. |
All of Opcos senior notes require annual principal payments in addition to semi-annual interest payments. The scheduled principal
payments on Opcos 4.73%, 5.03% and 5.18% senior notes will begin in December 2014. Opco also makes annual principal and interest payments on the utility local improvement obligation.
Revolving Credit Facility. As of September 30, 2014, Opco had $293 million in available borrowing capacity under its revolving
credit facility. Under an accordion feature in the credit facility, Opco may request its lenders to increase their aggregate commitment to a maximum of $500 million on the same terms. However, Opco cannot be certain that its lenders will elect to
participate in the accordion feature. To the extent the lenders decline to participate, Opco may elect to bring new lenders into the facility, but cannot make any assurance that the additional credit capacity will be available on existing or
comparable terms.
During 2014, Opcos borrowings and repayments under its credit facility were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ending |
|
|
|
March 31 |
|
|
June 30 |
|
|
September 30 |
|
|
|
(In thousands)
(Unaudited) |
|
Outstanding balance, beginning of period |
|
$ |
20,000 |
|
|
$ |
20,000 |
|
|
$ |
15,000 |
|
Borrowings under credit facility |
|
|
|
|
|
|
|
|
|
|
|
|
Less: Repayments under credit facility |
|
|
|
|
|
|
(5,000 |
) |
|
|
(8,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding balance, ending period |
|
$ |
20,000 |
|
|
$ |
15,000 |
|
|
$ |
7,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
Opcos obligations under its credit facility are unsecured but are guaranteed by its
subsidiaries. Opco may prepay all amounts outstanding under its credit facility at any time without penalty. Indebtedness under Opcos revolving credit facility bears interest, at our option, at either:
|
|
|
the Alternate Base Rate (as defined in the credit agreement) plus an applicable margin ranging from 0% to 1%; or |
|
|
|
the Adjusted LIBO Rate (as defined in the credit agreement) plus an applicable margin ranging from 1.00% to 2.25%. |
Opco incurs a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.18% to 0.40% per annum.
The Opco credit agreement contains covenants requiring Opco to maintain:
|
|
|
a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to exceed 4.0 to 1.0; and |
|
|
|
a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) not less than 3.5 to 1.0. |
Term Loan. In connection with the OCI Wyoming acquisition, Opco entered into a 3-year, $200 million term loan facility in January 2013.
The term loan facility is guaranteed by Opcos operating subsidiaries and bore interest at a weighted average rate of 2.23% for the nine months ended September 30, 2014. We repaid $101 million of the term loan during 2013. The remaining
balance of $99.0 million is due in January 2016. The term loan facility contains financial covenants and other terms that are identical to those of our credit facility.
NRP Oil and Gas Debt
Revolving Credit Facility. In August 2013, NRP Oil and Gas entered into a 5-year, $100 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. As of September 30, 2014, the credit facility has a borrowing base of $20.0
million. 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 NRP nor any of its
other subsidiaries is a guarantor of such facility. As of September 30, 2014, NRP Oil and Gas had $2.0 million outstanding under the facility.
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 1.75% to 2.75%. |
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 (i) 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 (ii) a current ratio of at least 1.0 to 1.0. The credit facility also contains other customary covenants, subject to
certain agreed exceptions, including covenants restricting the ability of NRP Oil and Gas to, among other items, incur indebtedness; create, assume or permit to exist liens; be a party to or be liable on any hedging contract; engage in mergers or
consolidations; transfer, lease, exchange, alienate or dispose of material assets or properties; pay distributions; make any acquisitions of, capital contributions to or other investments in any entity or property; extend credit or make advances or
loans; or engage in transactions with affiliates. Events of default under the credit facility include payment defaults, misrepresentations and breaches of covenants by NRP Oil and Gas. The credit facility also contains a cross-default provision with
respect to any indebtedness of NRP.
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 connection with the closing of the Kaiser-Francis acquisition, the NRP Oil and
Gas revolving credit facility will be amended. The amended facility is expected to be a $500 million facility with an initial borrowing base of $137 million and will mature on the date that is 5 years from the date of the closing. The amended
facility will be secured by a first priority lien and security
37
interest in substantially all of the assets of NRP Oil and Gas, including the assets acquired in the Kaiser-Francis acquisition. NRP Oil and Gas will be the sole obligor under the amended credit
facility, and neither NRP nor any of its other subsidiaries is a guarantor of such facility. The amended credit facility is expected to contain substantially similar pricing terms and covenants as the current facility, except that it will reduce the
applicable margin for LIBOR based loans.
Consolidated Debt
The following table reflects our long-term non-cancelable contractual obligations as of September 30, 2014 (in millions) (unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
Contractual Obligations |
|
Total |
|
|
Remaining 2014 |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
Thereafter |
|
NRP: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt principal payments (including current maturities)(1) |
|
$ |
300.0 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
300.0 |
|
|
$ |
|
|
Long-term debt interest payments(2) |
|
|
123.3 |
|
|
|
13.7 |
|
|
|
27.4 |
|
|
|
27.4 |
|
|
|
27.4 |
|
|
|
27.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
NRP Oil and Gas: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt principal payments |
|
|
2.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Opco: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt principal payments (including current maturities) (3) |
|
|
798.8 |
|
|
|
24.8 |
|
|
|
81.0 |
|
|
|
187.0 |
|
|
|
81.0 |
|
|
|
81.0 |
|
|
|
344.0 |
|
Long-term debt interest payments(4) |
|
|
195.5 |
|
|
|
8.6 |
|
|
|
38.4 |
|
|
|
33.3 |
|
|
|
28.2 |
|
|
|
23.2 |
|
|
|
63.8 |
|
Rental leases(5) |
|
|
2.9 |
|
|
|
0.2 |
|
|
|
0.7 |
|
|
|
0.7 |
|
|
|
0.7 |
|
|
|
0.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,422.5 |
|
|
$ |
47.3 |
|
|
$ |
147.5 |
|
|
$ |
248.4 |
|
|
$ |
137.3 |
|
|
$ |
434.2 |
|
|
$ |
407.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
On September 18, 2013, NRP and NRP Finance issued $300 million of 9.125% senior notes at an offering price of 99.007% of par value due October 1, 2018.
|
(2) |
The amounts indicated in the table include interest due on 9.125% senior notes. |
(3) |
The amounts indicated in the table include principal due on Opcos senior notes, as well as the utility local improvement obligation related to our property in
DuPont, Washington. On January 24, 2013, Opco entered into a $200 million three year term loan. As of December 31, 2013, there was $99.0 million outstanding which is due in January 2016. |
(4) |
The amounts indicated in the table include interest due on Opcos senior notes as well as the utility local improvement obligation related to our property in
DuPont, Washington. |
(5) |
On January 1, 2009, Opco entered into a ten-year lease agreement for the rental of office space from Western Pocahontas Properties Limited Partnership for $0.6
million per year. In addition, BRP leases office space for approximately $100,000 per year. These rental obligations are included in the table above. |
Shelf Registration Statements and At-the-Market Program
On April 24, 2012 we filed an automatically effective shelf registration statement on Form S-3 with the SEC that is available for
registered offerings of common units and debt securities. On October 10, 2014, we issued 8,500,000 common units in an underwritten public offering pursuant to this registration statement at a public offering price of $12.02 per common unit. We
intend to use the net proceeds of approximately $100.4 million from this offering, including our general partners proportionate capital contribution to maintain its 2% general partner interest in us, to fund a portion of the purchase price of
the Kaiser-Francis acquisition.
On August 15, 2012, we filed a shelf registration statement on Form S-3 that registered all of the
common units held by Adena Minerals. This shelf registration statement was declared effective by the SEC on September 21, 2012. Following the effectiveness of this registration statement, Adena distributed 15,181,716 common units to its
shareholders, and we subsequently filed prospectus supplements to register the resale of these common units by those shareholders. The shelf registration statement filed in August 2012 also registered up to $500 million in equity securities to be
sold by NRP. On November 12, 2013, we filed a prospectus supplement and entered into an Equity Distribution Agreement relating to the offer and sale from time to time of common units having an aggregate offering price of $75 million through one
or more managers acting as sales agents at prices to be agreed upon at the time of sale. Under the terms of the Equity Distribution Agreement, we may also sell common units from time to time to any manager as principal for its own account at a price
to be agreed upon at the time of sale. Any sale of common units to any manager as principal would be pursuant to the terms of a separate terms agreement between NRP and such manager. Sales of common units in this at-the-market
(ATM) program are made pursuant to the shelf registration statement declared effective in September 2012. For the nine months ended September 30, 2014, we sold 1,539,314 common units for an average price of $16.13 for gross proceeds
of $24.8 million.
38
On April 12, 2013, we filed a resale shelf registration statement on Form S-3 to register
the 3,784,572 common units issued in the January 2013 private placement in connection with the OCI Wyoming acquisition. This shelf registration statement was declared effective by the SEC in May 2013. A portion of the common units issued in the
private placement were issued, directly and indirectly, to certain of our affiliates, including Corbin J. Robertson, Jr. and Christopher Cline.
We cannot control the resale of the common units by any of the selling unitholders under the shelf registration statements described above,
and the amounts, prices and timing of the issuance and sale of any equity or debt securities by NRP will depend on market conditions, our capital requirements and compliance with our credit facilities, term loan and senior notes.
Off-Balance Sheet Transactions
We
do not have any off-balance sheet arrangements with unconsolidated entities or related parties and accordingly, there are no off-balance sheet risks to our liquidity and capital resources from unconsolidated entities.
Related Party Transactions
Reimbursements to our General Partner
Our general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in
accordance with our partnership agreement, we reimburse our general partner and its affiliates for expenses incurred on our behalf. All direct general and administrative expenses are charged to us as incurred. We also reimburse indirect general and
administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates. We had an amount payable to
Quintana Minerals Corporation of $0.5 million at September 30, 2014 for services provided by Quintana. Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.
The reimbursements to our general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands)
(Unaudited) |
|
Reimbursement for services |
|
$ |
2,927 |
|
|
$ |
2,748 |
|
|
$ |
8,708 |
|
|
$ |
8,481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For additional information, see Certain Relationships and Related Transactions, and Director
Independence Omnibus Agreement in our Annual Report on Form 10-K for the year ended December 31, 2013.
We also lease an
office building in Huntington, West Virginia from Western Pocahontas at market rates. The terms of the lease were approved by our Conflicts Committee. We pay $0.6 million each year in lease payments.
39
Cline Affiliates
Various companies controlled by Chris Cline lease coal reserves from NRP, and we provide coal transportation services to them for a fee.
Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in NRPs general partner, as well as 4,917,548 common units. Revenues from Cline affiliates are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands)
(Unaudited) |
|
Coal royalty revenues |
|
$ |
13,337 |
|
|
$ |
14,968 |
|
|
$ |
39,713 |
|
|
$ |
39,527 |
|
Transportation and processing fees |
|
|
5,358 |
|
|
|
5,121 |
|
|
|
15,557 |
|
|
|
14,471 |
|
Minimums recognized as revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,477 |
|
Override revenue |
|
|
478 |
|
|
|
957 |
|
|
|
2,156 |
|
|
|
2,735 |
|
Gain on reserve swap |
|
|
5,690 |
|
|
|
|
|
|
|
5,690 |
|
|
|
8,149 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal related revenues |
|
$ |
24,863 |
|
|
$ |
21,046 |
|
|
$ |
63,116 |
|
|
$ |
68,359 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2014, we had amounts due from Cline affiliates totaling $60.7 million, of which $53.9
million was attributable to agreements relating to Sugar Camp. As of September 30, 2014, we had received $82.7 million in minimum royalty payments to date that have not been recouped by Cline affiliates, of which $11.7 million was received in
the current year.
For the nine months ended September 30, 2014 and 2013, we recognized $5.7 million and $8.1 million non-cash gains,
on a coal reserve swap, in Illinois with Williamson Energy.
Quintana Capital Group GP, Ltd.
Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused on investments
in the energy business. In connection with the formation of Quintana Capital, we adopted a formal conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by Quintana Capital. The governance
documents of Quintana Capitals affiliated investment funds reflect the guidelines set forth in NRPs conflicts policy.
At
September 30, 2014, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal Corp., a coal mining company traded on the TSX Venture Exchange that is one of our lessees in Tennessee. Corbin J. Robertson III, one of our
directors, is Chairman of the Board of Corsa. Revenues from Corsa are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
|
|
(In thousands)
(Unaudited) |
|
Coal royalty revenues |
|
$ |
655 |
|
|
$ |
1,249 |
|
|
$ |
2,218 |
|
|
$ |
3,403 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We also had accounts receivable totaling $0.2 million from Corsa at September 30, 2014.
A fund controlled by Quintana Capital owned a significant membership interest in Taggart Global USA, LLC, including the right to nominate two
members of Taggarts 5-person board of directors. Subsequent to the end of the second quarter of 2013, Taggart was sold to Forge Group, and Quintana no longer retains an interest in Taggart or Forge. We own and lease 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.
Revenues from Forge for the nine months ended September 30, 2013 were $1.8 million. Subsequent to the second quarter of 2013, Forge is no
longer considered a related party of NRP.
Environmental
The operations our lessees conduct on our properties are subject to federal and state environmental laws and regulations. See
Item 1. BusinessRegulation and Environmental Matters in our Annual Report on Form 10-K for the year ended December 31, 2013. As an owner of surface interests in some properties, we may be liable for certain environmental
conditions occurring on the surface properties. The terms of substantially all of our 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 us against, among other things, environmental liabilities. Some of these indemnifications survive the
termination of the lease. Because we have no employees,
40
employees of Western Pocahontas Properties Limited Partnership make regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the
lessees. We believe that our lessees will be able to comply with existing regulations and do not expect any lessees failure to comply with environmental laws and regulations to have a material impact on our financial condition or results of
operations. We have neither incurred, nor are aware of, any material environmental charges imposed on us related to our properties at September 30, 2014. We are not associated with any environmental contamination that may require remediation
costs. However, our lessees do conduct reclamation work on the properties under lease to them. Because we are not the permittee of the mines being reclaimed, we are not responsible for the costs associated with these reclamation operations. In
addition, West Virginia has established a fund to satisfy any shortfall in reclamation obligations. During 2013, several citizen group lawsuits were filed against landowners alleging ongoing discharges of pollutants, including selenium, from valley
fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond has been released. While it is too early to
determine the merits or predict the outcome of any of these lawsuits, any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for
completed and reclaimed coal mine operations.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk, which includes adverse changes in commodity prices and interest rates as discussed below:
Commodity Price Risk
We are dependent
upon the effective marketing of the coal mined by our lessees. Our lessees sell the coal under various long-term and short-term contracts as well as on the spot market. As is customary in the coal industry, our coal is predominantly sold by our
lessees under coal supply contracts that have terms of one year or more. Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. Our
lessees failure to negotiate long-term contracts could adversely affect the stability and profitability of our lessees operations and adversely affect our coal royalty revenues. If more coal is sold on the spot market, coal royalty
revenues may become more volatile due to fluctuations in spot coal prices.
The market price of soda ash directly affects the
profitability of OCI Wyomings operations. If the market price for soda ash declines, OCI Wyomings sales will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash have been volatile, and
those markets are likely to remain volatile in the future. In addition, crude oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. These markets will likely continue to be volatile
in the future.
Interest Rate Risk
Our exposure to changes in interest rates results from our borrowings under our revolving credit facility and term loan, which are subject to
variable interest rates based upon LIBOR. At September 30, 2014, we had $108 million in variable interest rate debt. If interest rates were to increase by 1%, annual interest expense would increase approximately $1.1 million, assuming the same
principal amount remained outstanding during the year.
Item 4. Controls and Procedures
NRP carried out an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rules
13a-15(e) and 15d-15(e) of the Securities Exchange Act) as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of NRP management, including the Chief Executive Officer and
Chief Financial Officer of the general partner of the general partner of NRP. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures are effective in providing
reasonable assurance that (a) the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and
Exchange Commissions rules and forms, and (b) such information is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.
No changes were made to our internal control over financial reporting during the last fiscal quarter that materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
41
Part II. Other Information
Item 1. Legal Proceedings
We are 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, our management believes these claims will not have a material effect on our financial position, liquidity or operations.
Item 1A. Risk Factors
The following risk factors update the risk factors included in Natural Resource Partners L.P.s Form 10-K for the year ended
December 31, 2013. Other than the risk factors below, there are no material changes to the risk factors included therein.
We
are exposed to operating risks as a result of the VantaCore acquisition that we have not previously experienced.
Prior to the
VantaCore acquisition, we did not operate aggregates mining and production assets. VantaCore currently operates three hard rock quarries, six sand and gravel plants, two asphalt plants and a marine terminal. As an operator of these assets, we will
be exposed to risks that we have not historically been exposed to in our mineral rights and royalties business. Such risks include, but are not limited to, prices and demand for construction aggregates, capital and operating expenses necessary to
maintain VantaCores operations, production levels, general economic conditions, conditions in the local markets that VantaCore serves, inclement or hazardous weather conditions, permitting risk, fire, explosions or other accidents, and
unanticipated geologic conditions. Any of these risks could result in damage to, or destruction of, VantaCores mining properties or production facilities, personal injury, environmental damage, delays in mining or processing, reduced revenue
or losses or possible legal liability. In addition, not all of these risks are reasonably insurable, and our insurance coverage contains limits, deductibles, exclusions and endorsements. Our insurance coverage may not be sufficient to meet our needs
in the event of loss. Any prolonged downtime or shutdowns at VantaCores mining properties or production facilities or material loss could have an adverse effect on our results of operations and prevent us from realizing all of the anticipated
benefits of the acquisition.
We may incur unanticipated costs or delays in connection with the integration of VantaCore and future
aggregates operations into our company.
There are risks with respect to the integration of VantaCore into our company that may
result in unanticipated costs or delays to us. Such risks include:
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integrating additional personnel into our company, including the approximately 230 people employed by VantaCore; |
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establishing the internal controls and procedures for the acquired businesses that we are required to maintain under the Sarbanes-Oxley Act of 2002; |
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consolidating other corporate and administrative functions; |
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diversion of managements attention away from our other business concerns; |
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loss of key employees; and |
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the assumption of any undisclosed or other potential liabilities of the acquired company. |
Similar risks may apply to the integration of future aggregates operations that we may acquire through the VantaCore platform. Any significant
costs and delays resulting from the risks described above could cause us not to realize the anticipated benefits of these acquisitions.
42
Our reserve estimates depend on many assumptions that may be inaccurate, which could
materially adversely affect the quantities and value of our reserves.
Coal, aggregates and oil and natural gas reserve engineering
requires subjective estimates of underground accumulations of coal, aggregates and oil and natural gas and assumptions and are by nature imprecise. Our reserve estimates may vary substantially from the actual amounts of coal, aggregates and oil and
natural gas recovered our reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of reserves necessarily depend upon a number of variables and assumptions, any
one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to:
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future prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs; |
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future technology improvements; |
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the effects of regulation by governmental agencies; and |
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geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in areas where our lessees currently mine or the operators of our non-operated oil and
gas working interests currently produce. |
Actual quantities of reserves, production, revenue and expenditures with respect
to our reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on our reserve data.
The Kaiser-Francis acquisition may not be consummated, and the assumptions on which our estimates of future results of the
Kaiser-Francis assets have been based may prove to be incorrect in a number of material ways, resulting in us not realizing the expected benefits of the Kaiser-Francis acquisition.
The Kaiser-Francis acquisition is expected to close in November 2014 and is subject to closing conditions. If these conditions are not
satisfied or waived, the Kaiser-Francis acquisition will not be consummated. If the closing of the Kaiser-Francis acquisition is substantially delayed or does not occur at all, we may not realize the anticipated benefits of the Kaiser-Francis
acquisition fully or at all. Additionally, the assumptions on which our estimates of future results of the Kaiser-Francis assets have been based may prove to be incorrect in a number of material ways, resulting in us not realizing our expected
benefits of the Kaiser-Francis acquisition, including anticipated increased cash flow.
Item 2. Unregistered Sales of
Equity Securities and Use of Proceeds
In connection with the closing of the VantaCore acquisition, on October 1, 2014, we issued
2,426,690 common units to certain of the owners of VantaCore in exchange for their interests in VantaCore and VantaCore GP upon closing of the acquisition. The aggregate offering price of the common units was approximately $36 million. Such common
units were issued and sold in reliance upon an exemption from the registration requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof.
Item 3. Defaults Upon Senior Securities
None.
Item 4.
Mine Safety Disclosures
As a result of our acquisition of VantaCore, information concerning mine safety violations or other regulatory
matters required by SEC regulations is included in Exhibit 95.1 to this Quarterly Report on Form 10-Q.
Item 5. Other
Information
None.
43
Item 6. Exhibits
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2.1 |
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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 the Current Report
on Form 8-K filed on January 25, 2013). |
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2.2 |
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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). |
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2.3 |
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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 Exhibit 2.1 to Current Report on Form 8-K
filed on October 6, 2014). |
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3.1 |
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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) |
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3.2 |
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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 the Current Report on Form 8-K filed on September
21, 2010). |
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3.3 |
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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). |
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4.1 |
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First Amendment, dated March 6, 2012, to the Fourth Amended and Restated Agreement of Limited Partnership of
Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q filed on
August 7, 2012). |
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4.2 |
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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). |
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4.3 |
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Form of 9.125% Senior Notes due 2018 (contained in Exhibit 1 to Exhibit 4.2). |
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4.4 |
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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). |
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4.5 |
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Registration Rights Agreement, dated October 17, 2014, by and among Natural Resource Partners L.P., NRP Finance
Corporation and Wells Fargo Securities, LLC, as representative of the several initial purchasers (incorporated by
reference to Exhibit 4.4 to Current Report on Form 8-K filed on October 20, 2014). |
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10.1 |
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Limited Liability Company Agreement of OCI Wyoming LLC, dated June 30, 2014 (incorporated by reference to
Exhibit 10.1 to Current Report on Form 8-K filed by OCI Resources LP on July 2, 2014). |
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10.2 |
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Purchase Agreement dated October 9, 2014 by and among Natural Resource Partners L.P., NRP Finance Corporation
and Wells Fargo Securities, LLC (as the representative of the several initial purchasers) (incorporated by reference to
Exhibit 4.4 to Current Report on Form 8-K filed on October 10, 2014). |
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10.3* |
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Continued Employment and Separation Agreement dated effective as of September 1, 2014, by and among Natural
Resource Partners L.P., Western Pocahontas Properties Limited Partnership and Nick Carter. |
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31.1* |
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Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley. |
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31.2* |
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Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley. |
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32.1* |
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Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350. |
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32.2* |
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Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350. |
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95.1* |
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Mine Safety Disclosure. |
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101* |
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The following financial information from the Quarterly Report on Form 10-Q of Natural Resource Partners L.P. for the
quarter ended September 30, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated
Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to
Consolidated Financial Statements, tagged as blocks of text. |
* |
Filed or, in the case of Exhibits 32.1 and 32.2, furnished herewith. |
44
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned and thereunto duly authorized.
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NATURAL RESOURCE PARTNERS L.P. |
By: |
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NRP (GP) LP, its general partner |
By: |
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GP NATURAL RESOURCE PARTNERS LLC, its
general partner |
Date: November 7, 2014
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By: |
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/s/ Corbin J. Robertson, Jr. |
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Corbin J. Robertson, Jr.,
Chairman of the Board and Chief
Executive Officer (Principal Executive Officer) |
Date: November 7, 2014
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By: |
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/s/ Dwight L. Dunlap |
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Dwight L. Dunlap,
Chief Financial Officer and
Treasurer (Principal Financial
Officer) |
Date: November 7, 2014
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By: |
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/s/ Kenneth Hudson |
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Kenneth Hudson
Controller (Principal Accounting
Officer) |
45
Exhibit 10.3
CONTINUED EMPLOYMENT AND SEPARATION AGREEMENT
This Continued Employment and Separation Agreement (this Agreement) is made and entered into by and between
Natural Resource Partners L.P. (Company), Western Pocahontas Properties Limited Partnership (Employer) and Nick Carter (Executive) on this 1st day of September 2014 (the Effective Date).
WHEREAS,
Executive is currently employed by Employer and provides services to Employer and its affiliates;
WHEREAS, as a condition of
Executives continued employment by Employer and Executives receipt of the benefits provided herein, Executive agrees to enter into this Agreement; and
WHEREAS Executive desires to retire from certain positions that he holds with certain affiliates of Employer and the parties desire to
memorialize such retirement herein.
NOW, THEREFORE, in exchange for good and valuable consideration, the receipt of which is acknowledged
and agreed, and intending to be legally bound, Company, Employer and Executive enter into this Agreement.
1. Resignation from Officer
Positions; Continued Employment.
(a) Executive will voluntarily retire from his positions as President and Chief Operating
Officer of GP Natural Resource Partners LLC, NRP (Operating) LLC and NRP Oil and Gas LLC, as President of NRP Finance Corporation, as President of Western Pocahontas Corporation, the general partner of Employer, and as President of New Gauley Coal
Corporation effective as of September 1, 2014 (the Retirement Date).
(b) From the
Retirement Date through December 31, 2014 (Continuing Employment Period), subject to Section 5 below, Executive shall remain employed with Employer and will provide such services as may be necessary for the
transition of Executives duties and responsibilities while he was an officer of Company and Employer, as requested by the appropriate officers of Employer or Company from time to time, and to otherwise mentor, advise and promote the persons to
whom Executives duties and responsibilities will be transitioned. In addition, during the Continuing Employment Period and through December 31, 2016, Executive agrees to refer to Company, or otherwise provide reasonable assistance to
Company in its efforts to obtain transactions involving the acquisition of coal reserves, royalties and infrastructure. Executives employment with Employer will terminate on December 31, 2014 (the Termination
Date), as Executive has elected to voluntarily resign his employment as of such date and, as of such date, Employer shall no longer be employed by Company or any of its affiliates.
Page 1 of 8
2. Consideration.
(a) In consideration for Executives promises herein and provided that Executive continues to comply with the restrictive covenants set
forth in Section 3, Company (or, as applicable, Employer) shall:
(i) Continue to employ Executive through the Termination Date
(unless this Agreement is earlier terminated pursuant to Section 5 below) and, in so doing, pay Executive a base salary at the rate of $33,250 per complete calendar month (which amount includes Executives car allowance) during the period
of the Continuing Employment Period that Executive is employed hereunder pursuant to the regular payroll practice of Employer as may exist from time to time and subject to tax withholding and other payroll deductions.
(ii) Subject to the execution and delivery to Company of a release in the form attached as Exhibit A
(Release) on or after December 31, 2014 but no later than January 31, 2015 (and provided that Executive does not subsequently revoke such release in the time provided to do so), pay Executive an annual bonus with
respect to 2014 services equal to $133,000 (Bonus) on December 31, 2014, subject to tax withholding and other payroll deductions; provided, however, Executive will not be entitled to otherwise receive an annual
bonus or participate in any incentive compensation arrangements of Company, Employer or the affiliates of either entity (other than the vesting of the phantom units described in Section 2(a)(iii)) on and after the Retirement Date or with
respect to the year ending December 31, 2014, including, but not limited to the NRP (GP) LP management incentive pool.
(iii)
Provide for Executives continued participation in the other executive benefit plans and arrangements of Company and its affiliates in which Executive participated prior to the Retirement Date to the extent Executive is otherwise eligible to
participate in such arrangements pursuant to their terms.
(iv) Accelerate the vesting of any outstanding phantom units granted to
Executive under the Natural Resource Partners Long-Term Incentive Plan (Plan) and held by Executive as of the Retirement Date (Phantom Units). The Fair Market Value (as such term is
defined in the Plan) of the Phantom Units for purposes of settlement will be determined as of the Retirement Date. The Phantom Units will be settled pursuant to the terms of the agreements evidencing the Phantom Units and the Plan; provided,
however, that the retention of the cash payment received by Executive in settlement of the Phantom Units will be conditioned on the execution and delivery to Company of the Release or after December 31, 2014 but no later than January 31,
2015 (and the further condition that Executive does not subsequently revoke such release in the time provided to do so). In the event that Executive: (a) does not timely execute and deliver an effective Release pursuant to this
Section 2(a)(iv); (b) revokes such Release; or (c) otherwise materially violates a covenant set forth in Section 3, then Executive will be required to repay to Company, an amount in cash equal to the sum of (A) the Bonus and
(B) the Fair Market Value (as such term is defined in the Plan) of the Phantom Units as of the Retirement Date. Any such repayment owed pursuant to parts (a) or (b) of the preceding sentence shall be owed by Executive
within fifteen days of the delivery of written notice from Company that such repayment is required; any such repayment owed pursuant to part (c) of the preceding sentence shall be owed by Executive within fifteen days of a determination by a
court or arbitrator of competent jurisdiction that Executive has committed a breach as described in part (c). Company will withhold from the amounts payable pursuant to this Section 2(a)(iv) all federal, state, city, or other income or
employment taxes as may be required pursuant to any law or governmental regulation or ruling.
Page 2 of 8
(b) The consideration set forth in this Section 2 is referred to as the
Consideration.
3. Continuing Post-Employment Obligations.
(a) Executive acknowledges that Company has trade, business and financial secrets and other confidential and proprietary information
(collectively, the Confidential Information), that Executive has received such Confidential Information and that additional Confidential Information will be provided to Executive during the Continuing Employment Period.
Confidential information includes, but is not limited to, reserves, royalty and infrastructure information, technical information, strategic information, information about acquisition prospects, business plans, processes and compilations of
information, records, specifications and information concerning customers or vendors, customer and supplier lists, and information regarding methods of doing business. As defined herein, Confidential Information shall not include information that is
generally known to the public other than as a result of disclosure by Executive or any individual who has made such information known in breach of any duty of confidentiality.
(b) Executive acknowledges and agrees that the Confidential Information has been developed or acquired by Company through the expenditure of
substantial time, effort and money and provides Company with an advantage over competitors who do not know or use such Confidential Information and that Company would be irreparably harmed by any breach of this Section 3. Executive further
acknowledges and agrees that his violation of any of the covenants of Section 3(g) below may give rise to cause of action against him with remedies for Company in equity or at law.
(c) During and following the Continuing Employment Period, Executive shall hold in confidence and not directly or indirectly disclose or use
or copy or make lists of any Confidential Information except to the extent authorized in writing by the Chief Executive Officer, President or Vice President & General Counsel of GP Natural Resource Partners LLC or compelled by legal
process, other than to an Executive of Company or Employer or a person to whom disclosure is reasonably necessary or appropriate in connection with the performance by Executive of his duties pursuant to this Agreement. Executive agrees to use his
best efforts to give Company notice of any and all attempts to compel disclosure of any Confidential Information, in such a manner so as to provide Company with written notice at least five days before disclosure or within one business day after
Executive is informed that such disclosure is being or will be compelled, whichever is earlier. Such written notice shall include a description of the information to be disclosed, the court, government agency, or other forum through which the
disclosure is sought, and the date by which the information is to be disclosed, and shall contain a copy of the subpoena, order or other process used to compel disclosure.
(d) Executive further agrees not to use any Confidential Information for the benefit of any person or entity other than Company.
(e) All records, files, documents and materials (including all electronically stored information), or copies thereof, relating to
Companys business which Executive shall prepare, or use, or be provided with during the Continuing Employment Period or which
Page 3 of 8
Executive has prepared, or used, or been provided with as a result of his employment with Employer or any of its affiliates, shall be and remain the sole property of Employer or its affiliates,
as the case may be, and shall be returned promptly by Executive to Employer or its applicable affiliate upon termination of the Continuing Employment Period.
(f) During and following the Continuing Employment Period, Executive will cooperate with, and assist, Company in defense of any claim,
litigation or administrative proceeding brought against Company as reasonably requested by Company. Such cooperation and assistance shall include, but not be limited to, (i) interviews of Executive by legal counsel for Company as reasonably
requested by such counsel, (ii) Executive providing documents (or copies thereof) and executing affidavits as reasonably requested by such counsel, (iii) Executive appearing for depositions, trials, and other proceedings as reasonably
requested by such counsel, and (iv) unless otherwise prohibited by law, Executive only communicating with any party adverse to Company (or such partys representative) through legal counsel for Company. Company will pay all reasonable
out-of-pocket expenses incurred by Executive in providing such cooperation and assistance, provided such expenses have been pre-approved by Company. Nothing in this paragraph 3(f) is intended to cause Executive to testify other than truthfully
in any proceeding or affidavit or prevent any communication that is required by law.
(g) Executive acknowledges and agrees that
the nature of the Confidential Information would make it impossible for him to perform in a similar capacity for a Competing Business (as defined below) without disclosing or utilizing the Confidential Information. Executive further acknowledges and
agrees that Companys business is conducted throughout the Restricted Area in a highly competitive market. Accordingly, Executive agrees that he will not (other than for the benefit of Company) directly or indirectly, individually or as an
officer, director, Executive, shareholder, officer, contractor, partner, joint venturer, agent, equity owner or in any other capacity whatsoever, during the Restricted Period, directly or indirectly: (1) within the Restricted Area, engage in,
or assist any other person or entity in, any business involving the pursuit of coal reserve, royalty and infrastructure acquisitions (a Competing Business); (2) hire, attempt to hire, or contact or solicit with respect
to hiring any employee of Company, or (3) solicit, divert or take away any customers or customer leads of Company. For the avoidance of doubt, the foregoing sentence shall not preclude Executive from having roles with respect to the coal mining
operations so long as such roles do not violate any of the restrictions of Section 3(c) above. Notwithstanding the foregoing, nothing in this Agreement is intended to preclude Executive from serving as a member of the board of directors or
managers of a Competing Business, so long as Executive does not violate the provisions of Section 3(c) above in the course of such service and Executive recuses himself from any and all discussions regarding the acquisition of coal reserves,
royalties and infrastructure by such Competing Business. As used herein: (X) the Restricted Area is defined as the counties within the United States in which coal reserves are mined, produced or otherwise subject to
acquisition; and (Y) the Restricted Period is defined as the date beginning on the Effective Date and ending on: (i) December 31, 2030 with respect to all restrictions set forth in Section 3(g)(1) above
that relate to Pocahontas Land Corporation (Pocahontas Land) or the acquisition of Pocahontas Land or any of its assets; and (ii) December 31, 2016 with respect to all other prohibitions set forth in Sections
3(g)(1), 3(g)(2) and 3(g)(3) above.
Page 4 of 8
(h) Executive acknowledges that the geographic boundaries, scope of prohibited activities, and
time duration of the preceding paragraphs are reasonable in all respects and are no broader than are necessary to protect Companys legitimate business interests, including the preservation of their goodwill and the protection of the
Confidential Information. Executive further acknowledges and agrees that the restrictions set forth herein afford fair protection to the interests of Employer and Company, that Company has made significant investments in Executive and that the
restrictions on Executive do not interfere with the public interest or impose any undue hardships on Executive.
(i) If any court
determines that any portion of this Section 3 (or part thereof) is invalid or unenforceable, such portion (or part thereof) shall be severable and the remainder of this Section 3 shall not thereby be affected and shall be given full effect
without regard to the invalid provisions. If any court construes any of the provisions of this Section 3, or any part thereof, to be unreasonable because of the duration or scope of such provision, such court shall have the power to reduce the
duration or scope of such provision and to enforce such provision as so reduced.
(j) As used in this Section 3
Company shall include Natural Resource Partners L.P. and any of its affiliates, including Employer, and shall also include New Gauley Coal Corporation and Quintana Minerals Corporation and each of their respective
affiliates.
4. Warranties and Other Obligations of Executive. Executive agrees, represents and warrants that:
(a) The consideration provided to Executive herein, including Executives continued employment and the benefits set forth in
Section 2 above, is not something to which Executive is otherwise indisputably entitled but for his entry into this Agreement and is good and sufficient consideration for Executives entry into this Agreement.
(b) Executive is legally and mentally competent to sign this Agreement.
(c) Executive presently possesses the exclusive right to receive all of the consideration paid or provided in exchange for this Agreement.
5. Termination. Company may terminate this Agreement at any time between September 1, 2014 and December 31, 2014 with 30
days written notice to Executive, and Executive will be entitled to receive the consideration set forth in Sections 2(a)(i) only through the date of such termination and not thereafter. Upon termination of this Agreement, the provisions of
Section 3 shall continue provided Company has paid Executive the consideration set forth in Section 2(a)(ii) and (iv). The Agreement will expire on December 31, 2016, except as to the covenant set forth in Section 3(g)(i) related
to Pocahontas Land.
6. Choice of Law. This Agreement shall be interpreted and construed in accordance with and shall be governed
by the laws of the State of Delaware (without regard to any conflicts of law principle which would require the application of some other state law) and, when applicable, the laws of the United States.
Page 5 of 8
7. Entire Agreement. This Agreement constitutes the entire agreement of the parties
relating to the subject matter hereof. Any previous agreements with respect to this subject matter are superseded by this Agreement and are of no further force or effect. No term, provision or condition of this Agreement may be modified in any
respect except by a writing executed by both Executive and Company. No person has any authority to make any representation or promise on behalf of any of the parties not set forth in this Agreement. This Agreement has not been executed in reliance
upon any representation or promise except those contained herein.
8. Acknowledgment of Terms. Executive acknowledges that
Executive has carefully read this Agreement; that Executive has had the opportunity for review of it by Executives attorney; and that Executive is signing this Agreement knowingly and voluntarily.
9. Waiver. The failure of either party to enforce or to require timely compliance with any term or provision of this Agreement shall
not be deemed to be a waiver or relinquishment of rights or obligations arising hereunder, nor shall this failure preclude the enforcement of any term or provision or avoid the liability for any breach of this Agreement.
10. Severability. Each part, term or provision of this Agreement is severable from the others. Notwithstanding any possible future
finding by a duly constituted authority that a particular part, term or provision is invalid, void or unenforceable, this Agreement has been made with the clear intention that the validity and enforceability of the remaining parts, terms and
provisions shall not be affected thereby.
11. Construction. The headings in this Agreement are only for convenience and are not
intended to affect construction or interpretation. The plural includes the singular and the singular includes the plural; and and or are each used both conjunctively and disjunctively; any, all,
each, or every means any and all, and each and every; including and includes are each without limitation; and herein, hereof, hereunder and
other similar compounds of the word here refer to the entire Agreement and not to any particular paragraph, subparagraph, section or subsection.
12. Timing. Executive acknowledges and agrees Executive has had a reasonable time to consider this Agreement before executing it.
13. Advice to Consult Counsel. Company hereby advises Executive to consult with an attorney prior to executing this Agreement.
14. Survival. The respective rights and obligations of the parties hereunder shall survive any termination of this Agreement to the
extent necessary to the intended preservation of such rights and obligations. The provisions of this Section are in addition to the survivorship provisions of any other section of this Agreement.
15. Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of
which together will constitute one and the same Agreement. Signatures delivered by facsimile shall be deemed effective for all purposes.
Page 6 of 8
16. Third-Party Beneficiaries. Each affiliate of Company that is not a signatory
hereto shall be a third-party beneficiary of Executives obligations hereunder and be entitled to enforce such obligations as if a party hereto.
17. Section 409A. This Agreement is intended to be exempt from or compliant with Section 409A of the Internal Revenue Code of
1986, as amended, and the provisions of this Release shall be construed accordingly. Executives separation from service within the meaning of Treasury Regulation § 1.409A-1(h) is intended to be December 31, 2014.
18. Notices. All notices and other communications hereunder shall be in writing and shall be given by hand delivery to the other
party or by registered or certified mail, return receipt requested, postage prepaid, or by facsimile, as follows:
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If to Executive: |
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Nick Carter 925 Star Gaze Drive
Lexington, KY 40509 |
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If to Company: |
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Natural Resource Partners L.P. 601 Jefferson
St., Suite 3600 Houston, Texas 77002 Attn: Vice
President & General Counsel |
or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notice and
communications shall be effective when actually received by the addressee.
REMAINDER OF PAGE INTENTIONALLY LEFT BLANK
Page 7 of 8
|
NICK CARTER |
|
/s/ Nick Carter |
|
|
|
NATURAL RESOURCE PARTNERS L.P. |
|
|
By: |
|
NRP (GP) LP, its general partner |
|
By: GP Natural Resource Partners LLC, its general partner |
|
|
By: |
|
/s/ Dwight L. Dunlap |
Name: Dwight L. Dunlap |
Title: Chief Financial Officer and Treasurer |
|
|
|
WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP |
|
By: Western Pocahontas Corporation, its general partner |
|
|
By: |
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/s/ Dwight L. Dunlap |
Name: Dwight L. Dunlap |
Title: Chief Financial Officer and Treasurer |
Page 8 of 8
EXHIBIT A
GENERAL RELEASE AGREEMENT
This GENERAL RELEASE AGREEMENT (this Release) is that certain release referenced in
Section 2(a)(ii) and (iv) of the Continued Employment and Separation Agreement (the Agreement) made and entered into by and between Natural Resource Partners L.P. (Company), Western
Pocahontas Properties Limited Partnership (Employer) and Nick Carter (Executive) and effective as of the date signed by Executive as evidenced by the signature page below (the Effective
Date).
1. Release of Liability for Claims.
(a) For good and valuable consideration, including Executives receipt and ability to retain the benefits set forth in
Section 2(a)(ii) and (iv) of the Agreement, Executive hereby forever releases, discharges and acquits the Company, Employer, each of their respective subsidiaries and other affiliates, New Gauley Coal Corporation, Quintana Minerals
Corporation, and each of the foregoing entities respective predecessors, successors and past, present and future subsidiaries, affiliates, boards of directors (or comparable bodies) and all members thereof, shareholders, members, partners,
directors, officers, managers, employees, agents, attorneys, heirs, predecessors, successors and representatives in their personal and representative capacities, as well as all employee benefit plans maintained by a Company Party and all fiduciaries
and administrators of any such plans, in their personal and representative capacities (collectively, the Company Parties), from liability for, and Executive hereby waives, any and all claims, damages, or causes of action of
any kind, whether known or unknown, related to Executives employment with any Company Party, the termination of such employment, and any other acts or omissions related to any matter occurring or existing on or prior to the time that Executive
signs this Release, including without limitation, (i) any alleged violation through such date of: (A) any federal, state or local anti-discrimination or anti-retaliation law, including the Kentucky Civil Rights Act, the West Virginia Human
Rights Act, the Age Discrimination in Employment Act of 1967, as amended (including as amended by the Older Workers Benefit Protection Act), Title VII of the Civil Rights Act of 1964, as amended, the Civil Rights Act of 1991, Sections 1981
through 1988 of Title 42 of the United States Code, as amended, and the Americans with Disabilities Act of 1990, as amended; (B) the Employee Retirement Income Security Act of 1974, as amended (ERISA); (C) the
Immigration Reform Control Act, as amended; (D) the National Labor Relations Act, as amended; (E) the Occupational Safety and Health Act, as amended; (F) the Family and Medical Leave Act of 1993; (G) any federal, state or local
wage and hour law; (H) any other local, state or federal law, regulation, ordinance or orders which may have afforded any legal or equitable causes of action of any nature; or (I) any public policy, contract, tort, or common law claim or
claim for fraud or misrepresentation of any kind; (ii) any allegation for costs, fees, or other expenses including attorneys fees incurred in, or with respect to, a Released Claim; and (iii) any claim for compensation or benefits of
any kind not expressly set forth in this Release (collectively, the Released Claims). THIS RELEASE INCLUDES MATTERS ATTRIBUTABLE TO THE SOLE OR PARTIAL NEGLIGENCE (WHETHER GROSS OR SIMPLE) OR OTHER FAULT, INCLUDING
STRICT LIABILITY, OF ANY OF THE COMPANY PARTIES.
A-1
(b) Notwithstanding the above, the Released Claims do not include any claim that first arises
after the date that Executive signs this Release or any claim to vested benefits under an employee benefit plan of any Company Party that is subject to ERISA.
(c) Further notwithstanding this release of liability, nothing in this Agreement prevents Executive from filing any non-legally waivable
claim (including a challenge to the validity of this Agreement) with the Equal Employment Opportunity Commission (EEOC) or comparable state or local agency or participating in any investigation or proceeding
conducted by the EEOC or comparable state or local agency or cooperating with such agency; however, Executive understands and agrees that he is waiving any and all rights to recover any monetary or personal relief or recover as a result of such
EEOC or comparable state or local agency or proceeding or subsequent legal actions.
2. Representation About Claims. Executive
represents and warrants that Executive has made no assignment, sale, delivery, transfer or conveyance of any rights Executive has asserted or may have against any of the Company Parties with respect to any Released Claim.
3. Executives Acknowledgments. By executing and delivering this Release, Executive expressly acknowledges that:
|
(a) |
He has carefully read this Release and has had sufficient time to consider it; |
|
(b) |
He has been and hereby is advised in writing to discuss this Release with an attorney of his choice and he has had adequate opportunity to do so prior to executing this Agreement; |
|
(c) |
He fully understands the final and binding effect of this Release; the only promises made to him to sign this Release are those stated herein; and he is signing this Release knowingly, voluntarily and of his own free
will, and he understands and agrees to each of the terms of this Release; |
|
(d) |
The only matters relied upon by him and causing him to sign this Release are the provisions set forth in writing within the Agreement and the four corners of this document; and |
|
(e) |
He has had the opportunity to receive sufficient legal advice from advisors of his own choosing such that he enters into this Release with full understanding of the tax and legal implications thereof. |
4. Applicable Law. This Release is entered into under, and shall be governed for all purposes by, the laws of the State
of Delaware without reference to the principles of conflicts of law thereof.
A-2
5. Third-Party Beneficiaries. Executive expressly acknowledges and agrees that each
Company Party that is not a signatory to this Release shall be a third-party beneficiary of Section 1 of this Release.
6. Revocation Right. Notwithstanding the initial effectiveness of this Release, Executive may revoke the
delivery (and therefore the effectiveness) of this Release within the seven-day period beginning on the date Executive executes this Release (such seven day period being referred to herein as the Release Revocation Period).
To be effective, such revocation must be in writing signed by Executive and must be received by the Company, care of Vice President & General Counsel, Natural Resource Partners L.P., 601 Jefferson St., Suite 3600, Houston, Texas 77002, so
that it is received by such officer before 11:59 p.m. Houston, Texas time, on the last day of the Release Revocation Period. If an effective revocation is delivered in the foregoing manner and timeframe, then no consideration shall be retained to
Executive pursuant to Section 2(a)(ii) and (iv) of the Agreement (and Executive shall be required to return all such consideration) and this Release shall be of no force or effect and shall be null and void ab
initio.
7. Severability. Any term or provision of this Release (or part thereof) that renders
such term or provision (or part thereof) or any other term or provision (or part thereof) of this Release invalid or unenforceable in any respect shall be severable and shall be modified or severed to the extent necessary to avoid rendering such
term or provision (or part thereof) invalid or unenforceable, and such severance or modification shall be accomplished in the manner that most nearly preserves the benefit of the bargain under the Agreement.
8. Return of Property. Executive represents and warrants that he has returned to the Company all property belonging to the Company or
any other Company Party, including without limitation all computer files, electronically stored information and other materials provided to him by the Company or any other Company Party in the course of his employment and Executive further
represents and warrants that he has not maintained a copy of any such materials in any form. The parties agree and understand that Executive will maintain all of the contact information currently contained in his personal electronic devices.
9. Affirmation of Restrictive Covenants. In signing below, Executive affirms and represents that he will abide by the
restrictions set forth in Section 3 of the Agreement, which such restrictions (including those with respect to confidentiality, non-competition and non-solicitation), Executive acknowledges and agrees are reasonable and enforceable in all
respects and necessary to protect the Company Parties legitimate business interests. Executive further represents that he has received sufficient consideration to support such restrictions, has been employed for an appreciable length of time
after entering into the Agreement, and that he will suffer no undue hardship by complying with such restrictions.
10.
Interpretation. Titles and headings to Sections hereof are for the purpose of reference only and shall in no way limit, define or otherwise affect the provisions hereof. Unless the context requires otherwise, all references herein to an
agreement, instrument or other document shall be deemed to refer to such agreement, instrument or other document as amended, supplemented, modified and restated from time to time to the extent permitted by the provisions
A-3
thereof. The word or as used herein is not exclusive and is deemed to have the meaning and/or. The words herein, hereof, hereunder and
other compounds of the word here shall refer to the entire Agreement and not to any particular provision hereof. The use herein of the word including following any general statement, term or matter shall not be construed to
limit such statement, term or matter to the specific items or matters set forth immediately following such word or to similar items or matters, whether or not non-limiting language (such as without limitation, but not limited
to, or words of similar import) is used with reference thereto, but rather shall be deemed to refer to all other items or matters that could reasonably fall within the broadest possible scope of such general statement, term or matter.
[Signature page follows]
A-4
In signing below, I knowingly and voluntarily enter into this General Release Agreement and fully
and finally release any and all Released Claims (as defined in Section 1 above).
A-5
Exhibit 31.1
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
I, Corbin J. Robertson, Jr., certify that:
|
1) |
I have reviewed this report on Form 10-Q of Natural Resource Partners L.P. |
|
2) |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report; |
|
3) |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report; |
|
4) |
The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control
over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
|
a. |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
|
b. |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
|
c. |
Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and |
|
d. |
Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter
in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
|
5) |
The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the
registrants board of directors (or persons performing the equivalent functions); |
|
a. |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record,
process, summarize and report financial information; and |
|
b. |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
|
|
|
|
|
By: |
|
|
|
/s/ Corbin J. Robertson, Jr. |
Corbin J. Robertson, Jr. |
Chief Executive Officer |
Date: November 7, 2014
Exhibit 31.2
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
I, Dwight L. Dunlap, certify that:
|
1) |
I have reviewed this report on Form 10-Q of Natural Resource Partners L.P. |
|
2) |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report; |
|
3) |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report; |
|
4) |
The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control
over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
|
a. |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
|
b. |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
|
c. |
Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and |
|
d. |
Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter
in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
|
5) |
The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the
registrants board of directors (or persons performing the equivalent functions); |
|
a. |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record,
process, summarize and report financial information; and |
|
b. |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
|
|
|
|
|
By: |
|
|
|
/s/ Dwight L. Dunlap |
Dwight L. Dunlap |
Chief Financial Officer and Treasurer |
Date: November 7, 2014
Exhibit 32.1
CERTIFICATION OF
CHIEF
EXECUTIVE OFFICER
OF GP NATURAL RESOURCE PARTNERS LLC
PURSUANT TO 18 U.S.C. § 1350
In connection with the accompanying report on Form 10-Q for the quarter ended September 30, 2014 filed with the Securities and Exchange
Commission on the date hereof (the Report), I, Corbin J. Robertson, Jr., Chief Executive Officer and Chairman of the Board of GP Natural Resource Partners LLC, the general partner of the general partner of Natural Resource Partners L.P.
(the Company), hereby certify, to my knowledge, that:
|
1. |
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
|
2. |
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
|
|
|
/s/ Corbin J. Robertson, Jr. |
Name: |
|
Corbin J. Robertson, Jr. |
Date: |
|
November 7, 2014 |
Exhibit 32.2
CERTIFICATION OF
CHIEF
FINANCIAL OFFICER
OF GP NATURAL RESOURCE PARTNERS LLC
PURSUANT TO 18 U.S.C. § 1350
In connection with the accompanying report on Form 10-Q for the quarter ended September 30, 2014 filed with the Securities and Exchange
Commission on the date hereof (the Report), I, Dwight L. Dunlap, Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC, the general partner of the general partner of Natural Resource Partners L.P. (the
Company), hereby certify, to my knowledge, that:
|
3. |
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
|
4. |
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
|
|
|
/s/ Dwight L. Dunlap |
Name: |
|
Dwight L. Dunlap |
Date: |
|
November 7, 2014 |
Exhibit 95.1
MINE SAFETY DISCLOSURE
Our VantaCore mining operations are subject to regulation by the Federal Mine Safety and Health Administration (MSHA) under
the Federal Mine Safety and Health Act of 1977 (the Mine Act). MSHA inspects our mines on a regular basis and issues various citations and orders to our operators when its inspectors believe that a violation has occurred under
the Mine Act. We have disclosed below information regarding certain citations and orders issued by MSHA and related assessments and legal actions with respect to these mining operations. In evaluating the below information regarding mine
safety and health, investors should take into account factors such as: (i) the number of citations and orders will vary depending on the size of a mine, (ii) the number of citations issued will vary from inspector to inspector and mine to
mine, and (iii) citations and orders can be contested and appealed, and in that process are often reduced in severity and amount, and are sometimes dismissed or vacated. The tables below do not include any orders or citations issued to
independent contractors at our mines.
Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the
Dodd-Frank Act) requires issuers to include in periodic reports filed with the Securities and Exchange Commission (SEC) certain information relating to citations and orders for violations of standards under the Mine
Act. The following tables disclose information required under the Dodd-Frank Act for the three months ending September 30, 2014.
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Mine Name / MSHA Identification Number |
|
Section 104 S&S Citations(1) |
|
|
Section 104(b) Orders(2) |
|
|
Section 104(d) Citations
and Orders(3) |
|
|
Section 110(b)(2) Violations(4) |
|
|
Section 107(a) Orders(5) |
|
|
Total Dollar Value of MSHA Assessments Proposed(6) |
|
Laurel Aggregates/36-08891 |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
490.00 |
|
Southern Aggregates/16-01519 |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7 |
) |
Southern Aggregates/16-01388 |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
290.00 |
|
Southern Aggregates/16-00336 |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
224.00 |
|
Southern Aggregates/16-01536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
100.00 |
|
Southern Aggregates/16-01537 |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
150.00 |
|
Southern Aggregates/16-01408 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Winn Materials/40-03094 |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,307.00 |
|
(1) |
Mine Act section 104 S&S citations shown above are for alleged violations of mandatory health or safety standards that could significantly and substantially contribute to a mine health and safety hazard. It should
be noted that, for purposes of this table, S&S citations that are included in another column, such as Section 104(d) citations, are not also included as Section 104 S&S citations in this column. |
(2) |
Mine Act section 104(b) orders are for alleged failures to totally abate a citation within the time period specified in the citation. |
(3) |
Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with mandatory health or safety standards.
|
(4) |
Mine Act section 110(b)(2) violations are for an alleged flagrant failure (i.e., reckless or repeated) to make reasonable efforts to eliminate a known violation of a mandatory safety or health
standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury. |
(5) |
Mine Act section 107(a) orders are for alleged conditions or practices which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated and result in orders of
immediate withdrawal from the area of the mine affected by the condition. |
(6) |
Amounts shown include assessments proposed by MSHA during the three months ended September 30, 2014 on all citations and orders, including those citations and orders that are not required to be included within the
above chart. |
(7) |
Penalties have not yet been assessed. |
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Mine Name / MSHA Identification Number |
|
Total Number of Mining Related Fatalities |
|
|
Received Notice of Pattern
of Violations Under Section 104(e) (yes/no)(8) |
|
|
Legal Actions Pending as of Last Day of Period |
|
|
Legal Actions Initiated During Period |
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|
Legal Actions Resolved During Period |
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Laurel Aggregates/36-08891 |
|
|
|
|
|
|
no |
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Aggregates/16-01519 |
|
|
|
|
|
|
no |
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Aggregates/16-01388 |
|
|
|
|
|
|
no |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
Southern Aggregates/16-00336 |
|
|
|
|
|
|
no |
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Aggregates/16-01536 |
|
|
|
|
|
|
no |
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Aggregates/16-01537 |
|
|
|
|
|
|
no |
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Aggregates/16-01408 |
|
|
|
|
|
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no |
|
|
|
|
|
|
|
|
|
|
|
|
|
Winn Materials/40-03094 |
|
|
|
|
|
|
no |
|
|
|
4 |
|
|
|
3 |
|
|
|
4 |
|
(8) |
Mine Act section 104(e) written notices are for an alleged pattern of violations of mandatory health or safety standards that could significantly and substantially contribute to a mine safety or health hazard.
|
The number of legal actions pending before the Federal Mine Safety and Health Review Commission as of November 7, 2014
that fall into each of the following categories is as follows:
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|
|
Mine Name / MSHA Identification Number |
|
Contests of Citations and Orders |
|
|
Contests of Proposed Penalties |
|
|
Complaints for Compensation |
|
|
Complaints of Discharge/ Discrimination/ Interference |
|
|
Applications for Temporary Relief |
|
|
Appeals of Judges Rulings |
|
Laurel Aggregates/36-08891 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Southern Aggregates/16-01519 |
|
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|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
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|
|
Southern Aggregates/16-01388 |
|
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|
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1 |
|
|
|
|
|
|
|
|
|
|
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Southern Aggregates/16-00336 |
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Southern Aggregates/16-01536 |
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Southern Aggregates/16-01537 |
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Southern Aggregates/16-01408 |
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|
|
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|
Winn Materials/40-03094 |
|
|
2 |
|
|
|
8 |
|
|
|
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