NATURAL RESOURCE PARTNERS LP - Quarter Report: 2005 June (Form 10-Q)
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2005
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
SECURITIES EXCHANGE ACT OF 1934
Commission file number: 001-31465
NATURAL RESOURCE PARTNERS L.P.
(Exact name of registrant as specified in its charter)
Delaware | 35-2164875 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) |
601 Jefferson Street, Suite 3600
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)
(713) 751-7507
(Registrants telephone number, including area code)
(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 þ No o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of
the Exchange Act). Yes þ No o
At August 3, 2005 there were outstanding 13,986,906 Common Units and 11,353,658 Subordinated Units.
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Certification of CEO pursuant to Section 302 | ||||||||
Certification of CFO pursuant to Section 1350 | ||||||||
Certification of CEO pursuant to Section 1350 | ||||||||
Certification of CFO pursuant to Section 1350 |
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Forward-Looking Statements
Statements included in this Form 10-Q are forward-looking statements. In addition, we and our
representatives may from time to time make other oral or written statements which are also
forward-looking statements.
Such forward-looking statements include, among other things, statements regarding capital
expenditures, acquisitions and dispositions, expected commencement dates of coal mining, projected
quantities of future coal production by our lessees producing coal from our reserves and projected
demand or supply for coal that will affect sales levels, prices and royalties realized by us.
These forward-looking statements 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. Please read Risks
Related to Our Business beginning on page 24 for important factors that could cause our actual
results of operations or our actual financial condition to differ.
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Part I. Financial Information
Item 1. Financial Statements
NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
(In thousands)
June 30, | December 31, | |||||||
2005 | 2004 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 50,760 | $ | 42,103 | ||||
Accounts receivable |
18,446 | 15,058 | ||||||
Accounts receivable affiliate |
6 | 25 | ||||||
Other |
285 | 786 | ||||||
Total current assets |
69,497 | 57,972 | ||||||
Land |
14,110 | 13,721 | ||||||
Coal and other mineral rights, net |
530,961 | 523,844 | ||||||
Loan financing costs, net |
1,737 | 1,837 | ||||||
Other assets, net |
1,968 | 2,552 | ||||||
Total assets |
$ | 618,273 | $ | 599,926 | ||||
LIABILITIES AND PARTNERS CAPITAL |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 479 | $ | 576 | ||||
Accounts payable affiliate |
78 | 105 | ||||||
Current portion of long-term debt |
9,350 | 9,350 | ||||||
Accrued incentive plan expenses current portion |
1,685 | 1,559 | ||||||
Property, franchise and other taxes payable |
2,690 | 3,460 | ||||||
Accrued interest |
435 | 266 | ||||||
Total current liabilities |
14,717 | 15,316 | ||||||
Deferred revenue |
15,498 | 15,847 | ||||||
Accrued incentive plan expenses |
4,369 | 3,271 | ||||||
Long-term debt |
164,950 | 156,300 | ||||||
Partners capital: |
||||||||
Common units (outstanding: 13,986,906) |
248,503 | 243,814 | ||||||
Subordinated units (outstanding: 11,353,658) |
161,280 | 157,324 | ||||||
General partners interest |
9,439 | 8,802 | ||||||
Holders of incentive distribution rights |
345 | 105 | ||||||
Accumulated other comprehensive loss |
(828 | ) | (853 | ) | ||||
Total partners capital |
418,739 | 409,192 | ||||||
Total liabilities and partners capital |
$ | 618,273 | $ | 599,926 | ||||
The accompanying notes are an integral part of these financial statements.
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NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per unit data)
(In thousands, except per unit data)
Three months ended | Six months ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
Revenues: |
||||||||||||||||
Coal royalties |
$ | 37,957 | $ | 26,179 | $ | 70,487 | $ | 49,027 | ||||||||
Property taxes |
1,547 | 1,278 | 2,981 | 2,584 | ||||||||||||
Minimums recognized as revenue |
481 | 165 | 934 | 928 | ||||||||||||
Override royalties |
209 | 757 | 824 | 1,434 | ||||||||||||
Other |
1,503 | 1,118 | 2,718 | 1,886 | ||||||||||||
Total revenues |
41,697 | 29,497 | 77,944 | 55,859 | ||||||||||||
Operating costs and expenses: |
||||||||||||||||
Depletion and amortization |
8,625 | 7,214 | 16,504 | 14,283 | ||||||||||||
General and administrative |
3,162 | 2,422 | 6,474 | 5,133 | ||||||||||||
Property, franchise and other taxes |
1,954 | 1,712 | 3,784 | 3,369 | ||||||||||||
Coal royalty and override payments |
745 | 398 | 1,298 | 786 | ||||||||||||
Total operating costs and expenses |
14,486 | 11,746 | 28,060 | 23,571 | ||||||||||||
Income from operations |
27,211 | 17,751 | 49,884 | 32,288 | ||||||||||||
Other income (expense)
|
||||||||||||||||
Interest expense |
(2,570 | ) | (2,683 | ) | (5,027 | ) | (6,098 | ) | ||||||||
Interest income |
331 | 60 | 562 | 112 | ||||||||||||
Net income |
$ | 24,972 | $ | 15,128 | $ | 45,419 | $ | 26,302 | ||||||||
Net income attributable to: |
||||||||||||||||
General partner(1) |
$ | 1,155 | $ | 394 | $ | 1,985 | $ | 641 | ||||||||
Other holders of incentive distribution rights(1) |
$ | 353 | $ | 49 | $ | 580 | $ | 61 | ||||||||
Limited partners |
$ | 23,464 | $ | 14,685 | $ | 42,854 | $ | 25,600 | ||||||||
Basic and diluted net income per limited partner unit: |
||||||||||||||||
Common |
$ | 0.92 | $ | .58 | $ | 1.69 | $ | 1.05 | ||||||||
Subordinated |
$ | 0.92 | $ | .58 | $ | 1.69 | $ | 1.05 | ||||||||
Weighted average number of units outstanding: |
||||||||||||||||
Common |
13,987 | 13,987 | 13,987 | 12,902 | ||||||||||||
Subordinated |
11,354 | 11,354 | 11,354 | 11,354 | ||||||||||||
(1) | Other holders of the incentive distribution rights (IDRs) include the WPP Group (25%) and NRP Investment LP (10%). The net income allocated to the general partner includes the general partners portion of the IDRs (65%). |
The accompanying notes are an integral part of these financial statements.
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NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(In thousands)
Six months ended | ||||||||
June 30, | ||||||||
2005 | 2004 | |||||||
(Unaudited) | ||||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 45,419 | $ | 26,302 | ||||
Adjustments to reconcile net income to net
cash provided by operating activities: |
||||||||
Depletion and amortization |
16,504 | 14,283 | ||||||
Non-cash interest charge |
125 | 585 | ||||||
Change in operating assets and liabilities: |
||||||||
Accounts receivable |
(3,369 | ) | (3,208 | ) | ||||
Other assets |
601 | 657 | ||||||
Accounts payable |
(124 | ) | (422 | ) | ||||
Accrued interest |
169 | (414 | ) | |||||
Deferred revenue |
(2,331 | ) | (1,792 | ) | ||||
Accrued incentive plan expenses |
1,224 | 485 | ||||||
Property, franchise and other taxes payable |
(770 | ) | 15 | |||||
Net cash provided by operating activities |
57,448 | 36,491 | ||||||
Cash flows from investing activities: |
||||||||
Acquisition of land, coal and other mineral rights |
(21,544 | ) | (77,332 | ) | ||||
Net cash used in investing activities |
(21,544 | ) | (77,332 | ) | ||||
Cash flows from financing activities: |
||||||||
Proceeds from loans |
18,000 | 75,500 | ||||||
Repayment of loans |
(9,350 | ) | (111,850 | ) | ||||
Distributions to partners |
(35,897 | ) | (27,951 | ) | ||||
Contributions by general partner |
| 2,147 | ||||||
Proceeds from sale of 5,250,000 common units, net of transaction costs |
| 200,355 | ||||||
Redemption of 2,616,752 common units from Arch Coal, Inc.,
net of transaction costs |
| (100,121 | ) | |||||
Net cash provided by (used in) financing activities |
(27,247 | ) | 38,080 | |||||
Net increase (decrease) in cash and cash equivalents |
8,657 | (2,761 | ) | |||||
Cash and cash equivalents at beginning of period |
42,103 | 24,320 | ||||||
Cash and cash equivalents at end of period |
$ | 50,760 | $ | 21,559 | ||||
Supplemental cash flow information: |
||||||||
Cash paid during the period for interest |
$ | 4,712 | $ | 5,927 | ||||
The accompanying notes are an integral part of these financial statements.
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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 three and six months ended June 30, 2005 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 2004 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), a Delaware limited partnership, was formed
in April 2002 to own and manage certain coal royalty producing properties contributed to the
Partnership by Western Pocahontas Properties Limited Partnership, (WPP), Great Northern
Properties Limited Partnership, (GNP), New Gauley Coal Corporation, (NGCC) and Arch Coal, Inc.
(collectively predecessors or predecessor companies). The predecessor companies contributed
assets to the Partnership on October 17, 2002. There were no operations in the Partnership prior
to the contribution of the assets from the predecessor companies.
The Partnership engages principally in the business of owning and managing coal properties in
the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the
Western United States. The Partnership does not operate any mines. The Partnership leases coal
reserves through its wholly owned subsidiary, NRP (Operating) LLC, (NRP Operating), to
experienced mine operators under long-term leases that grant the operators the right to mine the
Partnerships coal reserves in exchange for royalty payments. The Partnerships lessees are
generally required to make payments to the Partnership based on the higher of a percentage of the
gross sales price or a fixed price per ton of coal sold, in addition to a minimum payment.
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.
2. Summary of Significant Accounting Policies
Reclassification
Certain reclassifications have been made to the prior years financial statements to conform
to current year classifications.
New Accounting Standards
Statement of Financial Accounting Standards No. 123R Accounting for Stock-Based
Compensation, revised in 2004, superseded APB No. 25. Awards under our Long Term Incentive Plan
have been accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R,
effective for the first quarter of 2006, requires us to recognize a cumulative effect of the
accounting change at the date of adoption based on the difference between the fair value of the
unvested awards and the intrinsic value recorded. Additionally, FAS 123R provides that grants
after the effective date must be accounted for using the fair value method which will require us to
estimate the fair value of the grant using the Black-Scholes or another method and charge the
estimated fair value to expense over the service or vesting period of the grant. FAS 123R requires
that the fair value be recalculated at each reporting date over the service or vesting period of
the grant. Use of the fair value method as compared with the intrinsic method, will not change the
total expense to be reflected for a grant but it may impact the period in which expense is
reflected by increasing expense in one period based upon the fair value calculation and lowering
expense in a different period. The Partnership is in the process of evaluating the impact of the
adoption of FAS 123R.
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3. Acquisition
Plum Creek
On March 3, 2005, the Partnership completed an acquisition of coal reserves from Plum Creek
Timber Company, Inc. The purchase price was $21.25 million and was funded through a combination of
the Partnerships revolving credit facility and $3.25 million in cash. This property consists of
approximately 85 million tons of coal reserves located on approximately 175,000 acres in Virginia,
West Virginia and Kentucky with most of the reserves leased under 29 leases. The Partnership also
assumed approximately $2.0 million in recoupable royalties that are included in deferred revenue on
the balance sheet.
4. Coal and Other Mineral Rights
The Partnerships coal and other mineral rights consist of the following:
June 30, | December 31, | |||||||
2005 | 2004 | |||||||
(In thousands) | ||||||||
(Unaudited) | ||||||||
Coal and other mineral rights |
$ | 658,097 | $ | 634,960 | ||||
Less accumulated depletion and amortization |
(127,136 | ) | (111,116 | ) | ||||
Net book value |
$ | 530,961 | $ | 523,844 | ||||
Six months ended | ||||||||
June 30, | ||||||||
2005 | 2004 | |||||||
(In thousands) | ||||||||
(Unaudited) | ||||||||
Total depletion and amortization expense on coal interests |
$ | 16,020 | $ | 13,793 | ||||
5. Long-Term Debt
Long-term debt consists of the following:
June 30, | December 31, | |||||||
2005 | 2004 | |||||||
(In thousands) | ||||||||
(Unaudited) | ||||||||
$175 million floating rate revolving credit facility, due October 2009 |
$ | 18,000 | $ | | ||||
5.55% senior notes, with semi-annual interest payments in June and
December, with annual principal payments in June, maturing in June 2023 |
53,400 | 56,700 | ||||||
4.91% senior notes, with semi-annual interest payments in June and
December, with annual principal payments in June, maturing in June 2018 |
67,900 | 73,950 | ||||||
5.55% senior notes, with semi-annual interest payments in June and
December, maturing June 2013 |
35,000 | 35,000 | ||||||
Total debt |
174,300 | 165,650 | ||||||
Less current portion of long term debt |
(9,350 | ) | (9,350 | ) | ||||
Long-term debt |
$ | 164,950 | $ | 156,300 | ||||
At June 30, 2005, the Partnership had an outstanding balance of $18 million on its revolving
credit facility, and the weighted average interest rate on the outstanding balance was 4.37%. The
Partnership incurs a commitment fee on the revolving credit facility at rates ranging from 0.30% to
0.40% per annum.
The Partnership was in compliance with all terms under its long-term debt as of June 30, 2005.
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6. Net Income Per Unit Attributable to Limited Partners
Net income per unit attributable to limited partners is based on the weighted-average number
of common and subordinated units outstanding during the period and is allocated in the same ratio
as quarterly cash distributions are made. Net income per unit attributable to limited partners is
computed by dividing net income attributable to limited partners, after deducting the general
partners 2% interest and incentive distributions, by the weighted-average number of limited
partnership units outstanding. Basic and diluted net income per unit attributable to limited
partners are the same since the Partnership has no potentially dilutive securities outstanding.
7. Related Party Transactions
Quintana Minerals Corporation, a company controlled by Corbin J. Robertson, Jr., Chairman and
CEO of GP Natural Resource Partners LLC, provided certain administrative services to the
Partnership and charged it for direct costs related to the administrative services. Total expenses
charged to the Partnership under this arrangement were $0.2 million and $0.4 million for the three
and six month periods ended June 30, 2005 and $0.3 million and $0.6 million for the same periods in
2004. These costs are reflected in general and administrative expenses in the accompanying
statements of income. At June 30, 2005, the Partnership also had accounts payable to affiliates of
$0.1 million, which includes general and administrative expense payable to Quintana Minerals
Corporation.
WPP provides certain administrative services for the Partnership. Total expenses charged to
the Partnership under this arrangement were $0.7 million and $1.3 million for the three and six
month periods ended June 30, 2005 and $0.7 million and $1.4 million for the same periods in 2004.
These costs are reflected in general and administrative expenses in the accompanying statements of
income.
8. Commitments and Contingencies
Legal
In July 2001, several counties in West Virginia with significant coal and timber production
experienced severe flooding. In response to the floods, numerous plaintiffs living in and around
the City of Mullens in Wyoming County have sued, among other defendants, Natural Resource Partners.
In Charles Ashley et al. v. Western Pocahontas Corporation, Western Pocahontas Properties Limited
Partnership and Natural Resource Partners L.P., the plaintiffs allege that coal mining and
timbering in Wyoming and Raleigh Counties, West Virginia, exacerbated the flood runoff and the
severity of the flooding that damaged the plaintiffs homes and businesses. This is only one of
dozens of similar flood-related actions now pending in the West Virginia state courts that have
been consolidated before a three-judge mass litigation panel.
The Partnership has filed a motion to dismiss NRP in this case on the theory that NRP did not
own any surface interests in Wyoming and Raleigh Counties and did not acquire coal interests in
Wyoming and Raleigh Counties until after the date of the July 2001 flood. The motion to dismiss
remains pending, but will likely not be ruled on soon because the mass litigation panel has thus
far chosen not to address either that motion or the many similar dispositive motions filed by other
defendants and now pending in flood cases before the mass litigation panel. The Ashley case is
currently scheduled for trial as to liability in March 2006. Any judgment as to damages, if any,
would be determined in a separate trial following the liability phase.
Although it is too early in the litigation to express any meaningful opinion as to the
outcome, the Partnerships management believes it has a good defense to this action. In addition,
pursuant to the Omnibus Agreement, the Partnership has made a demand on Western Pocahontas
Properties Limited Partnership for indemnification with respect to any damages NRP might suffer up
to $10 million.
The Partnership is also involved, from time to time, in various other 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.
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Environmental Compliance
The operations conducted on the Partnerships properties by its lessees 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 coal leases require the lessee to comply with
all applicable laws and regulations, including environmental laws and regulations. Lessees post
reclamation bonds assuring that reclamation will be completed as required by the relevant permit,
and substantially all of the leases require the lessee to indemnify the Partnership against, among
other things, environmental liabilities. Some of these indemnifications survive the termination of
the lease. Because Natural Resource Partners L.P. has no employees, WPP employees perform regular
visits to the mines to ensure compliance with lease terms, but the duty to comply with all
regulations rests with the lessees and the duty to enforce regulations rests with the appropriate
regulatory agencies. Management believes that the Partnerships lessees will be able to comply
with existing regulations and does not expect any lessees failure to comply with environmental
laws and regulations to have a material impact on its financial condition or results of operations.
The Partnership has neither incurred, nor is aware of, any material environmental charges imposed
on it related to its properties for the period ended June 30, 2005. The Partnership is not
associated with any environmental contamination that may require remediation costs. However,
lessees do, from time to time, conduct reclamation work on the properties under lease to them.
Because the Partnership is not the permittee of the mines being reclaimed, it is not responsible
for the costs associated with these reclamation operations. All of the Partnerships lessees are
required to post bonds to cover reclamation costs. In the event these bonds are insufficient, some
states, such as West Virginia have established funds to cover these shortfalls. The Partnership is
also indemnified by WPP, GNP, NGCC and Arch Coal, Inc., jointly and severally, until October 16,
2005 against environmental and tax liabilities attributable to the ownership and operation of the
assets contributed to the Partnership prior to the closing of the initial public offering in
October 2002. The environmental indemnity is limited to a maximum of $10.0 million.
9. Major Lessees
Coal royalty revenues from major lessees that exceeded ten percent of total revenues for the
periods indicated below are as follows:
Three months ended | Six months ended | |||||||||||||||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||||||||||||||||||
Revenues | Percent | Revenues | Percent | Revenues | Percent | Revenues | Percent | |||||||||||||||||||||||||
Dollars in thousands | Dollars in thousands | |||||||||||||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||||||||||
Lessee A |
$ | 4,868 | 12 | % | $ | 3,339 | 11 | % | $ | 8,927 | 11 | % | $ | 6,526 | 12 | % | ||||||||||||||||
Lessee B |
4,046 | 10 | % | 2,162 | 7 | % | 8,859 | 11 | % | 4,444 | 8 | % | ||||||||||||||||||||
Lessee C |
5,241 | 13 | % | 5,059 | 17 | % | 10,027 | 13 | % | 9,517 | 17 | % | ||||||||||||||||||||
Lessee D |
4,881 | 12 | % | 1,702 | 6 | % | 8,207 | 11 | % | 2,959 | 5 | % |
10. Incentive Plans
In February and April 2005, the directors of GP Natural Resource Partners LLC granted to
directors and key employees a total of 59,046 additional phantom units that vest in February 2009.
There were 224,129 phantom units outstanding at June 30, 2005. The Partnership accrued expenses
related to its plans to be reimbursed to its general partner of $1.0 million and $0.5 million for
the three months ended June 30, 2005 and 2004, respectively, and $2.0 million and $1.1 million for
the six months ended in the same periods, respectively. In connection with the Long-Term Incentive
Plans, cash payments of $0.8 million and $0.6 million were paid during the six months ended June
30, 2005 and 2004.
11. Distributions
On May 13, 2005, the Partnership paid a cash distribution equal to $0.6875 per unit, or $2.75
on an annualized basis, to unitholders of record on May 2, 2005.
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12. Subsequent Events
Acquisition
On June 1, 2005, the Partnership signed a definitive agreement to purchase interests in
approximately 144 million tons in the Illinois Basin for $105 million in three separate
transactions. The Partnership will acquire approximately 60% of the reserves in fee and will
receive an override on the remaining tons. On July 11, 2005, the Partnership closed the first of
the three transactions for $35 million. The acquisition included approximately 47.5 million tons,
of which approximately 75% are owned in fee. The Partnership will receive an override on the
remaining tons.
Senior Notes
On July 19, 2005, the Partnership completed a private placement of $50 million of senior
unsecured notes and committed to issue an additional $50 million of senior notes on January 19,
2006. Proceeds from the first $50 million were used to repay borrowings under the Partnerships
existing revolving credit facility. The senior notes will begin amortizing in July 2008 and bear
interest at 5.05% with an average life of approximately nine years.
Distributions
On July 20, 2005, the Partnership announced a $0.025 per unit increase in its quarterly
distributions to $0.7125 per unit, or $2.85 per unit on an annualized basis. The distribution is
payable on August 12, 2005 to unitholders of record on August 1, 2005.
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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. Form 10-K, as filed on February 28, 2005.
Executive Overview
We engage principally in the business of owning and managing coal properties in the three
major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western
United States. As of December 31, 2004, we controlled approximately 1.8 billion tons of proven and
probable coal reserves in nine states. For the six months ended June 30, 2005, approximately 59%
of the coal produced from our properties came from underground mines and approximately 41% came
from surface mines. As of December 31, 2004, approximately 69% of our reserves were low sulfur
coal. Included in our low sulfur reserves is compliance coal, which constitutes approximately 37%
of our reserves.
We lease coal reserves to experienced mine operators under long-term leases that grant the
operators the right to mine our coal reserves in exchange for royalty payments. As of June 30,
2005, our reserves were subject to 160 leases with 60 lessees. For the three months ended June 30,
2005, our lessees produced 14.1 million tons of coal generating $38.0 million in coal royalty
revenues from our properties and our total revenue was $41.7 million. For the six months ended June
30, 2005, our lessees produced 26.9 million tons of coal generating $70.5 million in coal royalty
revenues from our properties and our total revenue was $77.9 million.
Our revenue and profitability are dependent on our lessees ability to mine and market our
coal reserves. Generally, our lessees make payments to us based on the greater of a percentage of
the gross sales price or a fixed price per ton of coal they sell, subject to minimum monthly,
quarterly or annual payments. In addition, our leases specify minimum monthly, quarterly or annual
royalties. These minimum royalties are generally recoupable over a specified period of time
(usually three to five years) if sufficient royalties are generated from coal production in future
periods. We do not recognize these minimum coal 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.
Most of our coal is produced by large companies, many of which are publicly traded, with
professional and sophisticated sales departments. We estimate that 80% of our coal is sold by our
lessees under coal supply contracts that have terms of one year or more. However, over the long
term, our coal royalty revenues are affected by changes in the market price of coal.
Coal prices are based on supply and demand, specific coal characteristics, economics of
alternative fuel, and overall domestic and international economic conditions. Beginning in the
latter half of 2003, the combination of the weaker U.S. dollar, especially against the Euro and the
Australian dollar, and the increase in ocean-going freight rates caused an increase in demand for
export coal because the United States was better able to compete with Australia for the European
market. Our lessees located in Appalachia have experienced a greater demand for coal, and coal
prices for both metallurgical and steam coal for those producers increased during 2004. Because of
these generally higher prices, our revenues in Appalachia have increased to an average of $2.83 per
ton for the six months ended June 30, 2005 from an average of $2.19 per ton for the same period of
2004. Coal royalty revenues from our Appalachian properties represented 91% of our total coal
royalty revenues for the six months ended June 30, 2005. In spite of the higher prices, most of our
lessees have not appreciably increased production due to a number of constraints, including a
shortage of labor, permitting issues and rail transportation problems.
For the six months ended June 30, 2005, approximately 33% of our coal royalty revenues were
from metallurgical coal, which was sold to steel companies in the Eastern United States, South
America, Europe and Asia. Prices of metallurgical coal have been
substantially higher over the
last two years. Metallurgical coal, because of its unique chemical characteristics, is usually
priced higher than steam coal. The current pricing environment for U.S. metallurgical coal is
strong in both the domestic and seaborne export markets.
On July 8, 2004, the United States District Court for the Southern District of West Virginia
issued an opinion and an injunctive order in the case of Ohio Valley Environmental Coalition, et
al. v. William Bulen. Judge Joseph Goodwin granted summary judgment for the plaintiffs and
enjoined further permitting by the Army Corps of Engineers in Southern West Virginia under the
Nationwide Permit 21 program. His order only impacts counties in Southern West Virginia and
requires applicants in those counties to seek individual permits, which require a more intensive
environmental review and public comment. Judge Goodwin also ordered the Corps of Engineers to tell
the companies that had received 11 permits issued by the Corps office in Huntington, West Virginia
since January
12
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2002 to halt any work under those permits where construction of the fills had not started at
the time of the July 8 order. Pending the resolution of any appeals, this decision will
dramatically slow down the permitting process for our lessees in Southern West Virginia, and the
increased cost of obtaining permits could render some of our smaller blocks of reserves uneconomic
to develop.
In January 2005, a lawsuit was filed in Eastern District of Kentucky on similar grounds
challenging the legality of Nationwide Permit 21. In March 2005, the plaintiffs filed a motion for
summary judgment requesting the court to (1) issue a declaratory judgment that Nationwide Permit 21
violates Section 404 of the Clean Water Act and (2) issue an injunction prohibiting the Corps from
issuing further authorizations pursuant to Nationwide Permit 21 in Kentucky. The motion also
requested the court to suspend those authorizations for valley fills on which the placement of
mining spoil in streams had not commenced as of the date of filing of the motion. On June 9, 2005,
the judge transferred the case from the Lexington Division to the Pikeville Division. The new judge
has yet to schedule arguments on the motion. Should the district court follow the reasoning of
Ohio Valley Environmental Coalition v. Bulen and similarly enjoin the Corps of Engineers from
authorizing further general permits under Nationwide Permit 21, permittees may have to file for
individual permits for fills that will result in increases in the costs of mining coal. We will
continue to monitor this litigation and its impact on the development of our coal reserves.
In addition to coal royalty revenues, other revenues accounted for approximately 3% of our
total revenues for each of the six month periods ended June 30, 2005 and 2004. Other revenues
consist of: rentals; royalties on oil and gas and coalbed methane leases; timber; overriding
royalty arrangements; and wheelage payments, which are toll payments for the right to transport
third-party coal over or through our property.
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 critical measure of our success as
a company. Distributable cash flow is also the quantitative standard used throughout the
investment community with respect to publicly traded partnerships.
Distributable cash flow represents cash flow from operations less actual principal payments
and cash reserves set aside for scheduled principal payments on our senior notes. 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 NRP as for other companies. A reconciliation of distributable cash flow to net cash
provided by operating activities is set forth below.
Reconciliation of GAAP Net cash provided by operating activities
to Non-GAAP Distributable cash flow
to Non-GAAP Distributable cash flow
Three months ended | Six months ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
(Unaudited) | ||||||||||||||||
Cash flow from operations |
$ | 31,378 | $ | 17,570 | $ | 57,448 | $ | 36,491 | ||||||||
Less scheduled principal payments |
(9,350 | ) | (9,350 | ) | (9,350 | ) | (9,350 | ) | ||||||||
Less reserves for future principal payments |
(2,350 | ) | (2,350 | ) | (4,700 | ) | (4,700 | ) | ||||||||
Add reserves used for scheduled principal payments |
9,400 | 9,400 | 9,400 | 9,400 | ||||||||||||
Distributable cash flow |
$ | 29,078 | $ | 15,270 | $ | 52,798 | $ | 31,841 | ||||||||
13
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Acquisitions
2005 Acquisitions
Plum Creek. On March 3, 2005, we completed an acquisition of coal reserves from Plum Creek
Timber Company, Inc. The purchase price was $21.25 million and was funded through a combination of
our revolving credit facility and $3.25 million in cash. This property consists of approximately
85 million tons of coal reserves located on approximately 175,000 acres in Virginia, West Virginia
and Kentucky with most of the reserves leased under 29 leases. We also assumed approximately $2.0
million in recoupable royalties that are included in deferred revenue.
Steelhead. On June 1, 2005, we signed a definitive agreement to purchase interests in
approximately 144 million tons in the Illinois Basin for $105 million in three separate
transactions. We will acquire approximately 60% of the reserves in fee and will receive an
override on the remaining tons. On July 11, 2005, we closed the first of the three transactions for
$35 million. The acquisition included approximately 47.5 million tons, of which approximately 75%
are owned in fee. We will receive an override on the remaining tons.
2004 Acquisitions
Clinchfield. In September 2004, we purchased a tract of coal reserves from Clinchfield Coal
Company in Dickenson County, Virginia for $0.4 million. This property adjoins other property we
own and represents approximately 0.8 million tons. We subsequently combined this property with
other properties under an existing lease to a subsidiary of Alpha Natural Resources.
Pardee Minerals. In May 2004, we purchased a tract of coal reserves from Pardee Minerals LLC
in Wise County, Virginia for $1.6 million. This property adjoins other property we own and
represents approximately 1.0 million tons. As a part of this transaction, we took an assignment of
a coal lease under which a subsidiary of Alpha Natural Resources is the lessee.
Appolo. In February 2004, we purchased two tracts of property from Appolo Fuels, Inc. in Bell
County, Kentucky for $2.5 million. This property adjoins the properties purchased in the BLC
acquisition and represents approximately 2.5 million tons. As a part of this transaction, an older
below market lease affecting approximately 2.5 million additional tons of adjacent reserves was
renegotiated to current royalty rates.
BLC Properties. In January 2004, we purchased all of the mineral interests of BLC Properties
LLC for $73.0 million. This acquisition included coal, oil and gas and other mineral rights on
approximately 270,000 acres that contain approximately 176 million tons of coal reserves. We lease
these reserves to eight different lessees. The transaction also included oil and gas and other
mineral rights on approximately 205,000 additional acres. The properties are located in Kentucky,
Tennessee, West Virginia, Virginia, and Alabama. BLC retained a 35% non-participating royalty
interest in the oil and gas and other mineral rights.
Critical Accounting Policies
Coal Royalties. We recognize coal royalty revenues on the basis of tons of coal sold by our
lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us
based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they
sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are
generally recoupable over a specified period of time (usually three to five years) if sufficient
royalties are generated from coal production in future periods. We do not recognize these minimum
coal royalties as revenue until the applicable recoupment period has expired or they are recouped
through production. Until recognized as revenue, these minimum royalties are carried as deferred
revenue, a liability on the balance sheet.
Timber Royalties. We primarily sell timber on a contract basis where independent contractors
harvest and sell the timber. From time to time, we also sell timber in a competitive bid process.
We recognize timber revenues when the independent contractors have harvested the timber, because
title and risk of loss pass to the independent contractors at that time. When our timber is sold
in a competitive bid process, we recognize revenue upon completion of the sale.
Oil and Gas Royalties. Oil and gas royalties are recognized on the basis of volume of
hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the
lessees make payments based on a percentage of the selling price. Some leases are subject to
minimum annual payments or delay rentals. The minimum annual payments that are recoupable are
generally recoupable over certain periods. The minimum payments are initially recorded as
deferred revenue and recognized either when the lessee recoups the minimum payments through
production or when the period during which the lessee is allowed to recoup the
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minimum payment expires.
Depletion. We deplete coal properties on a units-of-production basis by lease, based upon
coal mined in relation to the net cost of the mineral properties and estimated proved and probable
tonnage in those properties. We estimate proven and probable coal reserves with the assistance of
third-party mining consultants, and we use estimation techniques and recoverability assumptions.
Our estimates of coal reserves are updated periodically and may result in adjustments to coal
reserves and depletion rates that are recognized prospectively. Historical revisions have not been
material. Timberlands are stated at cost less depletion. We determine the cost of the timber
harvested based on the volume of timber harvested in relation to the amount of estimated net
merchantable volume by geographic areas. We estimate our timber inventory using statistical
information and data obtained from physical measurements and other information gathering
techniques. We update these estimates annually, which may result in adjustments of timber volumes
and depletion rates that are recognized prospectively. Changes in these estimates have no effect on
our cash flow.
New Accounting Standards
Statement of Financial Accounting Standards No. 123R Accounting for Stock-Based
Compensation, revised in 2004, superseded APB No. 25. Awards under our Long Term Incentive Plan
have been accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R,
effective for the first quarter of 2006, requires us to recognize a cumulative effect of the
accounting change at the date of adoption based on the difference between the fair value of the
unvested awards and the intrinsic value recorded. Additionally, FAS 123R provides that grants
after the effective date must be accounted for using the fair value method which will require us to
estimate the fair value of the grant using an accepted method and charge the
estimated fair value to expense over the service or vesting period of the grant. FAS 123R requires
that the fair value be recalculated at each reporting date over the service or vesting period of
the grant. Use of the fair value method as compared with the intrinsic method, will not change the
total expense to be reflected for a grant but it may impact the period in which expense is
reflected by increasing expense in one period based upon the fair value calculation and lowering
expense in a different period. We are in the process of evaluating the impact of the adoption of
FAS 123R.
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Results of Operations
Natural Resource Partners L.P.
Three months ended | Six months ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
(In thousands, except per ton data) | ||||||||||||||||
(Unaudited) | ||||||||||||||||
Revenues: |
||||||||||||||||
Coal royalties |
$ | 37,957 | $ | 26,179 | $ | 70,487 | $ | 49,027 | ||||||||
Property taxes |
1,547 | 1,278 | 2,981 | 2,584 | ||||||||||||
Minimums recognized as revenue |
481 | 165 | 934 | 928 | ||||||||||||
Override royalties |
209 | 757 | 824 | 1,434 | ||||||||||||
Other |
1,503 | 1,118 | 2,718 | 1,886 | ||||||||||||
Total revenues |
41,697 | 29,497 | 77,944 | 55,859 | ||||||||||||
Expenses: |
||||||||||||||||
Depletion and amortization |
8,625 | 7,214 | 16,504 | 14,283 | ||||||||||||
General and administrative |
3,162 | 2,422 | 6,474 | 5,133 | ||||||||||||
Property, franchise and other taxes |
1,954 | 1,712 | 3,784 | 3,369 | ||||||||||||
Coal royalty and override payments |
745 | 398 | 1,298 | 786 | ||||||||||||
Total expenses |
14,486 | 11,746 | 28,060 | 23,571 | ||||||||||||
Income from operations |
27,211 | 17,751 | 49,884 | 32,288 | ||||||||||||
Other income (expense): |
||||||||||||||||
Interest expense |
(2,570 | ) | (2,683 | ) | (5,027 | ) | (6,098 | ) | ||||||||
Interest income |
331 | 60 | 562 | 112 | ||||||||||||
Net income |
$ | 24,972 | $ | 15,128 | $ | 45,419 | $ | 26,302 | ||||||||
Other Data: |
||||||||||||||||
Coal royalties |
||||||||||||||||
Appalachia |
$ | 34,345 | $ | 24,390 | $ | 63,997 | $ | 45,672 | ||||||||
Illinois Basin |
1,093 | 783 | 2,400 | 1,498 | ||||||||||||
Northern Powder River Basin |
2,519 | 1,006 | 4,090 | 1,857 | ||||||||||||
Total |
$ | 37,957 | $ | 26,179 | $ | 70,487 | $ | 49,027 | ||||||||
Production (tons) |
||||||||||||||||
Appalachia |
11,740 | 10,537 | 22,611 | 20,868 | ||||||||||||
Illinois Basin |
707 | 692 | 1,574 | 1,298 | ||||||||||||
Northern Powder River Basin |
1,665 | 806 | 2,697 | 1,492 | ||||||||||||
Total |
14,112 | 12,035 | 26,882 | 23,658 | ||||||||||||
Average gross royalty per ton |
||||||||||||||||
Appalachia |
$ | 2.93 | $ | 2.31 | $ | 2.83 | $ | 2.19 | ||||||||
Illinois Basin |
1.55 | 1.13 | 1.52 | 1.15 | ||||||||||||
Northern Powder River Basin |
1.51 | 1.25 | 1.52 | 1.24 | ||||||||||||
Total |
$ | 2.69 | $ | 2.18 | $ | 2.62 | $ | 2.07 | ||||||||
Three months ended June 30, 2005 compared with three months ended June 30, 2004
Revenues. For the three months ended June 30, 2005, coal royalty revenues were $38.0 million
on 14.1 million tons of coal produced, compared to $26.2 million in coal royalty revenues on 12.0
million tons of coal produced for the second quarter of 2004, representing a 45% increase in coal
royalty revenues and a 17% increase in production. Coal royalty revenues comprise 91% of our total
revenue, with property taxes, minimums recognized as revenue, override royalties and other totaling
$3.7 million, or 9% of total revenue.
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The following is a breakdown of our major coal producing regions:
Appalachia. As a result of significantly higher prices, coal royalty revenues in Appalachia
for the quarter ended June 30, 2005 were $34.3 million compared to $24.4 million for the same
period in 2004, an increase of $9.9 million or 40%. For the quarter ended June 30, 2005,
production in Appalachia was 11.7 million tons compared to 10.5 million tons for the same period in
2004, an increase of 1.2 million tons or 11%.
The following properties generated significantly higher production and/or coal royalty
revenues during the quarter ended June 30, 2005.
| Pinnacle production increased from 325,000 tons to 788,000 tons while coal royalty revenues increased from $992,000 to $3.3 million. The increased tonnage was due to the mine operating on our property for the entire quarter versus only a portion of the quarter in the previous year. | ||
| Sincell production increased from 157,000 tons to 661,000 tons and coal royalty revenues increased from $281,000 to $1.1 million. The increased production was due to a longwall unit moving onto our property. | ||
| Eunice production increased from 378,000 tons to 781,000 tons and coal royalty revenues increased from $756,000 to $1.9 million. The increased tonnage was due to higher production by the longwall unit which produced from our property for a greater portion of the three months ended June 30, 2005. | ||
| BLC Properties production increased from 906,000 tons to 1.1 million tons and coal royalty revenues increased from $2.3 million to $3.5 million. These increases in tonnage were due to a combination of some lessees increasing production and some having a greater proportion of production on our property, which offset reductions by a lessee who experienced geologic problems. | ||
| KY Land production increased from 538,000 tons to 758,000 tons and coal royalty revenues increased from $1.4 million to $2.5 million. The increased tonnage was due to a combination of lessees increasing production and some having a greater proportion of production on our property. | ||
| Dorothy production increased from 349,000 tons to 510,000 tons and coal royalty revenues increased from $735,000 to $1.5 million. The increased tonnage was due to additional producing units being on our property. | ||
| Eastern Kentucky Property production increased from 16,000 tons to 224,000 tons and coal royalty revenues increased from $42,000 to $742,000. The increased production was due to a greater proportion of production from the mine being on our owned property. | ||
| Lynch production increased from 1.1 million tons to 1.4 million tons and coal royalty revenues increased from $2.1 million to $3.0 million. The increased tonnage was due to new mines being opened on the property. | ||
| Kingston production increased from 274,000 tons to 440,000 tons and coal royalty revenues increased from $506,000 to $1.3 million. The increased tonnage was due to additional producing units being on our property and a new surface mine starting on the property. | ||
| Plum Creek production increased from zero to 174,000 tons and coal royalty revenue increased from zero to $541,000, due to the March 2005 acquisition of the property. |
These increases were partially offset by lower production on our West Fork and Evans-Lavier
properties. Production on our West Fork property decreased from 786,000 tons to zero and royalty
revenues decreased from $2.4 million to zero as longwall mining was completed on our property.
Production on our Evans-Lavier property decreased from 929,000 tons to 393,000 tons and coal
royalty revenues decreased from $1.3 million to $713,000 due to a smaller proportion of production
coming from our property.
Illinois Basin. As a result of higher prices, coal royalty revenues in the Illinois Basin for
the quarter ended June 30, 2005 were $1.1 million compared to $0.8 million for the same period in
2004, an increase of $0.3 million or 39%. For the quarter ended June 30,
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2005, production in the Illinois Basin was 707,000 tons compared to 692,000 tons for the same
period in 2004, an increase of 15,000 tons or 2%.
Northern Powder River Basin. Production from our Western Energy property increased from
806,000 tons to 1.7 million tons and coal royalty revenues increased from $1.0 million to $2.5
million. These increases were due to the typical variations in production resulting from the
checkerboard ownership pattern and a higher sales price being realized by our lessee.
Expenses. For the quarter ended June 30, 2005, total expenses were $14.5 million, compared
to $11.7 million for the second quarter of 2004, representing an increase of $2.8 million, or 24%.
Included in total expenses are:
| Depletion and amortization of $8.6 million for the second quarter of 2005, compared to $7.2 million for the second quarter of 2004, an increase of $1.4 million, or 19% primarily due to the increase in production volumes; | ||
| General and administrative expenses of $3.2 million for the second quarter of 2005, compared to $2.4 million for the second quarter of 2004, an increase of $0.8 million, or 33%. Most of the increase in general and administrative expenses is attributable to compensation expenses for additional staff required to manage the properties we acquired as well as accruals under our long-term incentive compensation plans due to the increase in our unit price; and | ||
| Property, franchise and other taxes of $2.0 million for the second quarter of 2005, compared to $1.7 million for the second quarter of 2004, an increase of $0.3 million, or 18%, due to an increase in franchise taxes for 2005, as well as, taxes on additional properties acquired since last year. |
Interest Expense. For the quarter ended June 30, 2005, interest expense was $2.6 million
compared to $2.7 million for 2004, a decrease of $0.1 million. This decrease is attributed to
lower outstanding balances on our credit facility and senior notes during the second quarter of
2005.
Six months ended June 30, 2005 compared with six months ended June 30, 2004
Revenues. For the six months ended June 30, 2005, coal royalty revenues were $70.5 million on
26.9 million tons of coal produced, compared to $49.0 million in coal royalty revenues on 23.7
million tons of coal produced for the first half of 2004, representing a 44% increase in coal
royalty revenues and a 14% increase in production. Coal royalty revenues comprise 90% of our total
revenue, with property taxes, minimums recognized as revenue, override royalties and other totaling
$7.5 million, or 10% of total revenue.
The following is a breakdown of our major coal producing regions:
Appalachia. As a result of significantly higher prices, coal royalty revenues in Appalachia
for the six months ended June 30, 2005 were $64.0 million compared to $45.7 million for the same
period in 2004, an increase of $18.3 million or 40%. For the six months ended June 30, 2005,
production in Appalachia was 22.6 million tons compared to 20.9 million tons for the same period in
2004, an increase of 1.7 million tons or 8%.
The following properties generated significantly higher production and/or coal royalty
revenues during the six months ended June 30, 2005.
| Pinnacle production increased from 325,000 tons to 1.4 million tons while coal royalty revenues increased from $988,000 to $5.3 million. The increased tonnage was due to the mine resuming production after being idle during a portion of the six months ended June 30, 2004. | ||
| Sincell production increased from 219,000 tons to 1.5 million tons and coal royalty revenues increased from $376,000 to $2.7 million. The increased production was due to a longwall unit moving onto our property. | ||
| Eunice production increased from 1.0 million tons to 1.7 million tons and coal royalty revenues increased from $2.0 million to $4.3 million. The increased tonnage was due to higher production by the longwall unit on our property. |
18
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| Lynch production increased from 2.0 million tons to 2.6 million tons and coal royalty revenues increased from $3.7 to $5.6 million. The increased production was due to new mines being opened on the property. | ||
| BLC Properties production increased from 1.7 million tons to 1.9 million tons and coal royalty revenues increased from $4.1 million to $6.5 million. These increases in tonnage were due to a combination of some lessees increasing production and some having a greater proportion of production on our property, which offset reductions by a lessee who experienced geologic problems. | ||
| KY Land production increased from 1.1 million tons to 1.3 million tons and coal royalty revenues increased from $2.9 million to $4.3 million. The increased tonnage was due to a combination of lessees increasing production and some having a greater proportion of production on our property. | ||
| Dorothy production increased from 715,000 tons to 1.0 million tons and coal royalty revenues increased from $1.5 million to $3.0 million. The increased tonnage was due to additional producing units being on our property. | ||
| Eastern Kentucky Property production increased from 37,000 tons to 353,000 tons and coal royalty revenues increased from $98,000 to $1.1 million. The increased production was due to a greater proportion of production from the mine being on our property. | ||
| Kingston production increased from 622,000 tons to 804,000 tons and coal royalty revenues increased from $1.1 million to $2.2 million. The increased tonnage was due to an additional producing unit being on our property and a new surface mine starting on the property. | ||
| Plum Creek production from our Plum Creek properties increased from zero to 253,000 tons and coal royalty revenue increased from zero to $723,000, due to the March 2005 acquisition of the property. |
These increases were partially offset by lower production on our West Fork, Evans-Lavier and
VICC/Alpha properties. Production on our West Fork property decreased from 1.6 million tons to
zero and coal royalty revenues decreased from $4.2 million to zero as longwall mining was completed
on our property. On our Evans-Lavier property, production decreased from 1.7 million tons to
869,000 tons and coal royalty revenues decreased from $2.4 million to $1.5 million as a lower
proportion of the production was on our property. On our VICC/Alpha property, production decreased
from 3.8 million tons to 3.3 million tons but coal royalty revenues increased from $7.7 million to
$8.4 million. The decrease in production was due to a combination of a lower proportion of the
production being on our property and mines exhausting their reserves and geologic problems. The
increased sales price realized by our lessees offset this lower production resulting in higher coal
royalty revenue.
Illinois Basin. As a result of higher prices and increased production, coal royalty revenues
in the Illinois Basin for the six months ended June 30, 2005 were $2.4 million compared to $1.5
million for the same period in 2004, an increase of $0.9 million or 60%. For the six months ended
June 30, 2005, production in the Illinois Basin was 1.6 million tons compared to 1.3 million tons
for the same period in 2004, an increase of 276,000 tons or 21%.
On our Cummings/Hocking Wolford property, production increased from 597,000 tons to 812,000
tons and coal royalty revenues increased from $641,000 to $1.1 million. The increased production
was due to a greater proportion of production being on our property and an increase in the royalty
rate under the lease terms. Our Sato property production increased from 398,000 tons to 544,000
tons and coal royalty revenues increased from $540,000 to $909,000. The increased production was
due to higher production from the active mine on our property. These increases in production were
partially offset by lower production on our Trico property where production decreased from 303,000
tons to 218,000 tons but coal royalty revenues increased from $318,000 to $362,000 due to higher
sales prices being received by our lessee. The decrease in production was due to exhaustion of a
portion of the reserves at the mine.
Northern Powder River Basin. Production from our Western Energy property increased from 1.5
million tons to 2.7 million tons and coal royalty revenues increased from $1.9 million to $4.1
million. These increases were due to the typical variations in production resulting from the
checkerboard ownership pattern and higher sales prices being received by our lessee.
Expenses. For the six months ended June 30, 2005, total expenses were $28.1 million,
compared to $23.6 million for the first half of 2004, representing an increase of $4.5 million, or
19%. Included in total expenses are:
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| Depletion and amortization of $16.5 million for the first half of 2005, compared to $14.3 million for the same period of 2004, an increase of $2.2 million, or 15% due to the increase in production volumes; | ||
| General and administrative expenses of $6.5 million for the first half of 2005, compared to $5.1 million for the first six months of 2004, an increase of $1.4 million, or 27%. Most of the increase in general and administrative expenses is attributable to compensation expenses for additional staff required to manage the properties we acquired as well as accruals under our long-term incentive compensation plans due to the increase in our unit price; and | ||
| Property, franchise and other taxes of $3.8 million for the six months ended June 30, 2005, compared to $3.4 million for the first six months of 2004, an increase of $0.4 million, or 12%, due to an increase in franchise taxes for 2005. |
Interest Expense. For the six months ended June 30, 2005, interest expense was $5.0 million
compared to $6.1 million for 2004, a decrease of $1.1 million. This decrease is attributed to
lower outstanding balances on our credit facility and senior notes during the first half of 2005.
Related Party Transactions
Partnership Agreement
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,
our general partner and its affiliates are reimbursed 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. Reimbursements to affiliates of our general
partner may be substantial and will reduce our cash available for distribution to unitholders. The
reimbursements to affiliates of our general partner for services performed by Western Pocahontas
Properties and Quintana Minerals Corporation totaled $0.8 million and $1.7 million for the three
and six month periods ended June 30, 2005 and $1.0 million and $2.0 million for the three and six
month periods ended June 30, 2004, respectively.
Alpha Natural Resources
First Reserve, which has the right to nominate two members to the board of directors of GP
Natural Resource Partners LLC, has a significant interest in Alpha Natural Resources, which is one
of our largest lessees. We have entered into a number of coal mining leases with Alpha through a
combination of new leases entered into upon our purchase of the Alpha property and through leases
we had with entities that Alpha acquired. The leases we have with Alpha or related companies
consist of the following properties:
| VICC/Alpha in Virginia, which contains 362.5 million tons of proven and probable reserves as of December 31, 2004. | ||
| Kingwood in West Virginia, which contains 17.8 million tons of proven and probable reserves as of December 31, 2004. | ||
| Welch/Wyoming in West Virginia, which contains 7.5 million tons of proven and probable reserves as of December 31, 2004. | ||
| KY Land in Kentucky, which contains 20.3 million tons of proven and probable reserves as of December 31, 2004. | ||
| Plum Creek property in Kentucky, which contains 11.6 million tons of proven and probable reserves as of December 31, 2004. |
The Alpha leases in general have terms of five to ten years with the ability to renew the
leases for subsequent terms of five to ten years, until the earlier to occur of: (1) delivery of
notice that the lessee will not renew the lease or (2) all mineable and merchantable coal has been
mined. The leases provide for payments to us based on the higher of a percentage of the gross
sales price or a fixed minimum per ton of coal sold from the properties, with minimum annual
payments. Under the Alpha leases minimum royalty payments are credited against future production
royalties.
Coal royalty revenues payable under these leases for the six months ended June 30, 2005
totaled $10.0 million, representing 14.3% of our total coal royalty revenues. If no production had
taken place in 2005, minimum recoupable royalties of $2.6 million would have been payable under the
leases. At June 30, 2005 we had accounts receivable outstanding of $1.8 million with Alpha Natural
Resources.
We believe the production and minimum royalty rates contained in the Alpha leases are
consistent with current market royalty rates.
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Foundation Coal Holdings, Inc.
First Reserve also has a significant interest in Foundation Coal Holdings, Inc. who controls
our lessee on the Kingston property in West Virginia, which contains approximately 7.7 million tons
of proven and probable reserves as of December 31, 2004.
The Kingston lease has a term of ten years with the ability to renew the lease for subsequent
terms of five years unless the lessee gives notice it will not renew the lease. The lease provides
for payments to us based on the higher of a percentage of the gross sales price or a fixed minimum
per ton of coal sold from the properties, with annual minimum payments. Under the Kingston lease
minimum royalty payments are credited against future production royalties. We believe the
production and minimum royalty rates contained in the Kingston lease are consistent with current
market royalty rates.
Coal royalty revenues payable under the Kingston lease for the six months ended June 30, 2005
totaled $2.2 million, representing 3.1% of our coal royalty revenues. If no production had taken
place in 2005, minimum recoupable royalties of $0.3 million would have been payable under the
lease. At June 30, 2005 we had accounts receivable outstanding of $0.4 million with Foundation Coal
Holdings, Inc.
Liquidity and Capital Resources
Cash Flows and Capital Expenditures
We satisfy our working capital requirements with cash generated from operations. Since our
initial public offering, we have financed our property acquisitions through borrowings under our
revolving credit facility, the issuance of our senior notes and the issuance of additional common
units. We believe that cash generated from our operations, combined with the availability under
our credit facility and the proceeds from the issuance of debt and equity, will be sufficient to
fund working capital, capital expenditures and future acquisitions. Our ability to satisfy debt
service obligations, fund planned capital expenditures, make acquisitions and pay distributions to
our unitholders will depend upon our ability to access the capital markets, as well as our future
operating performance, which will be affected by prevailing economic conditions in the coal
industry and financial, business 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 our operations,
please read Risks Related to Our Business. Our capital expenditures, other than for acquisitions,
have historically been minimal.
Net cash provided by operations for the six months ended June 30, 2005 and 2004 was $57.4
million and $36.5 million, respectively. Substantially all of our cash provided by operations is
generated from coal royalty revenues.
Net cash used in investing activities for the six months ended June 30, 2005 was $21.5 million
compared to $77.3 million for 2004. The 2005 results include the acquisition of coal reserves from
Plum Creek Timber Company, Inc. Net cash used in investing activities for 2004 include the
acquisitions of coal reserves from BLC and Apollo.
Net cash used by financing activities for the six months ended June 30, 2005 was $27.2 million
compared to net cash provided by financing activities of $38.1 million for the same period a year
ago. In the six months ended June 30, 2005, we borrowed $18.0 million under our credit facility to
fund the Plum Creek acquisition, paid $9.4 million in principal payments on our senior notes and we
made distributions to our partners totaling $35.9 million. During the six months ended June 30,
2004, results include $200.4 million in net proceeds from our equity offering in March 2004, a $2.1
million capital contribution from our general partner to maintain its 2% general partner interest,
as well as $75.5 million in proceeds from borrowings on our credit facility. We used $102.5 million
of the net proceeds from the equity offering to pay the outstanding balance on our credit facility
and $100.1 million to redeem 2.6 million common units owned by Arch Coal. We also paid
distributions to our partners totaling $28 million.
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Contractual Obligations and Commercial Commitments
At June 30, 2005, our debt consisted of:
| $18 million outstanding under our $175 million revolving credit facility that matures in October 2009; | ||
| $53.4 million of 5.55% senior notes due 2023, with a 10-year average life; | ||
| $68 million of 4.91% senior notes due 2018, with a 7.5-year average life; and | ||
| $35 million of 5.55% senior notes due 2013. |
On July 19, 2005, we issued an additional $50 million of 5.05% senior notes due 2020, with an
approximate 9-year average life. The proceeds from the issuance of the senior notes were used to
repay borrowings under the revolving credit facility so that as of August 3, 2005, $175 million was
available for borrowing under the credit facility.
Credit Facility. On October 29, 2004, NRP (Operating) LLC entered into a 5-year, $175 million
revolving credit facility with Citigroup Global Markets, Inc. and Wachovia Capital Markets, LLC as
joint lead arrangers. The new credit facility replaced NRP Operatings previous 3-year facility,
which would have expired in October 2005. In addition to substantially improved pricing terms, the
new facility permits NRP Operating to increase the size of the facility up to $300 million without
obtaining lender consents.
Our obligations under the new credit facility are unsecured but are guaranteed by our
operating subsidiaries. We may prepay all loans at any time without penalty. Indebtedness under
the revolving credit facility bears interest, at our option, at either:
| the higher of the federal funds rate plus an applicable margin ranging from 0.25% to 1.00% or the prime rate as announced by the agent bank; or | ||
| at a rate equal to LIBOR plus an applicable margin ranging from 1.25% to 2.00%. |
We incur a commitment fee on the revolving credit facility at rates ranging from 0.30% to
0.40% per annum.
The credit agreement contains covenants requiring us to maintain:
| a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) of 3.75 to 1.0 for the four most recent quarters; provided however, if during one of those quarters we have made an acquisition, then the ratio shall not exceed 4.0 to 1.0 for the quarter in which the acquisition occurred and (1) if the acquisition is in the first half of the quarter, the next two quarters or (2) if the acquisition is in the second half of the quarter, the next three quarters; and | ||
| a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of 4.0 to 1.0 for the four most recent quarters. |
Senior Notes. NRP Operating LLC issued the senior notes under a note purchase agreement. The
senior notes are unsecured but are guaranteed by our operating subsidiaries. We 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 note purchase agreement contains covenants requiring our operating subsidiary to:
| 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 EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0. |
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The following table reflects our long-term non-cancelable contractual obligations as of June
30, 2005 (in millions):
Payments due by period(1) | ||||||||||||||||||||||||||||
Contractual Obligations | Total | 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | |||||||||||||||||||||
Long-term debt
(including current
maturities) |
$ | 238.29 | $ | 4.11 | $ | 17.33 | $ | 16.85 | $ | 16.38 | $ | 33.90 | $ | 149.72 | ||||||||||||||
(1) The amounts indicated in the table include principal and interest due on our senior notes. |
Shelf Registration Statement
On December 23, 2003, we and our operating subsidiaries jointly filed a $500 million
universal shelf registration statement with the Securities and Exchange Commission for the
proposed sale of debt and equity securities. Securities issued under this registration statement
may be in the form of common units representing limited partner interests in Natural Resource
Partners or debt securities of NRP or any of our operating subsidiaries. We currently have
approximately $290.2 million available under our registration statement. The registration
statement also covers, for possible future sales, up to 373,715 common units held by Great Northern
Properties Limited Partnership.
The securities may be offered from time to time directly or through underwriters at amounts,
prices, interest rates and other terms to be determined at the time of any offering. The net
proceeds from the sale of securities from the shelf will be used for future acquisitions and other
general corporate purposes, including the retirement of existing debt. We will not receive any
proceeds from the sale of common units by Great Northern Properties.
On June 28, 2005, we filed a shelf registration statement at the request of FRC-WPP NRP
Investment L.P., which owns 4,796,920 subordinated units. The registration statement registered
the 4,796,920 subordinated units and the common units into which they convert. FRC-WPP NRP
Investment L.P. may sell these units from time to time under the registration statement, and we
will not receive any proceeds from the sale of the units.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a
material impact on operations for the first six months of 2005 or 2004.
Environmental
The operations our lessees conduct on our properties are subject to environmental laws and
regulations adopted by various governmental authorities in the jurisdictions in which these
operations are conducted. As an owner of surface interests in some properties, we may be liable
for certain environmental conditions occurring at 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,
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 for the period
ended June 30, 2005. 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 our lessees reclamation obligations. We are also indemnified
by Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited
Partnership, New Gauley Coal Corporation and Arch Coal, Inc., jointly and severally, until October
17, 2005 against environmental and tax liabilities attributable to the ownership and operation of
the
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assets contributed to us prior to the closing of the initial public offering. The
environmental indemnity is limited to a maximum of $10.0 million.
Risks Related to Our Business
| We may not have sufficient cash from operations to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner. | ||
| A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our coal reserves. | ||
| Our lessees coal mining operations are subject to operating risks that could result in lower coal royalty revenues to us. | ||
| We depend on a limited number of primary operators for a significant portion of our coal royalty revenues, and the loss of or reduction in production from any of our major operators could reduce our coal royalty revenues. | ||
| We may not be able to terminate our leases, and we may experience delays and be unable to replace lessees that do not make royalty payments. | ||
| If our lessees do not manage their operations well, their production volumes and our coal royalty revenues could decrease. | ||
| Adverse developments in the coal industry could reduce our coal royalty revenues, and could substantially reduce our total revenues due to our lack of asset diversification. | ||
| Any decrease in the demand for metallurgical coal could result in lower coal production by our lessees, which would thereby reduce our coal royalty revenues. | ||
| We may not be able to expand and our business will be adversely affected if we are unable to replace or increase our reserves or obtain other mineral reserves through acquisitions. | ||
| Any change in fuel consumption patterns by electric power generators resulting in a decrease in the use of coal could result in lower coal production by our lessees, which would reduce our coal royalty revenues. | ||
| Competition within the coal industry may adversely affect the ability of our lessees to sell coal, and excess production capacity in the industry could put downward pressure on coal prices. | ||
| Lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments. | ||
| Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from our properties. | ||
| Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our reserves. | ||
| Our lessees work forces could become increasingly unionized in the future. | ||
| We may be exposed to changes in interest rates because any current borrowings under our revolving credit facility may be subject to variable interest rates based upon LIBOR. | ||
| Our lessees are subject to federal, state and local laws and regulations that may limit their ability to produce and sell coal from our properties. | ||
| A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period. |
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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 and efficient mining of our coal reserves by our
lessees. Our lessees sell coal under various long-term and short-term contracts as well as on the
spot market. A large portion of these sales are under long-term contracts. The coal industry in
Appalachia is experiencing an increase in both domestic and foreign demand, as well as a shortage
of supply. As a result, the current price of coal in Appalachia is
substantially higher. If this price
level is not sustained or our lessees costs increase, some of our coal could become uneconomic to
mine, which would adversely affect our coal royalty revenues. In addition, the current prices may
make coal from other regions more economical and may make other competing fuels relatively less
costly than Appalachian coal.
Interest Rate Risk
Our exposure to changes in interest rates results from our borrowings under our revolving
credit facility, which may be subject to variable interest rates based upon LIBOR. At June 30,
2005, we had outstanding $18.0 million in variable interest rate debt. If LIBOR rates were to
increase by 100 basis points, annual interest expense would increase by $180,000, assuming the same
principal amount remained outstanding over the next twelve months.
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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 producing the timely recording, processing,
summarizing and reporting of information and in accumulating and communicating information to
management as appropriate to allow for timely decisions with regard to 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.
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Part II. Other Information
Item 1. Legal Proceedings
In July 2001, several counties in West Virginia with significant coal and timber production
experienced severe flooding. In response to the floods, numerous plaintiffs living in and around
the City of Mullens in Wyoming County have sued, among other defendants, Natural Resource Partners.
In Charles Ashley et al. v. Western Pocahontas Corporation, Western Pocahontas Properties Limited
Partnership and Natural Resource Partners L.P., the plaintiffs allege that coal mining and
timbering in Wyoming and Raleigh Counties, West Virginia, exacerbated the flood runoff and the
severity of the flooding that damaged the plaintiffs homes and businesses. This is only one of
dozens of similar flood-related actions now pending in the West Virginia state courts that have
been consolidated before a three-judge mass litigation panel.
We have filed a motion to dismiss NRP in this case on the theory that we do not own any
surface interests in Wyoming and Raleigh Counties and did not acquire our coal interests in Wyoming
and Raleigh Counties until after the date of the July 2001 flood. The motion to dismiss remains
pending, but will likely not be ruled on soon because the mass litigation panel has thus far chosen
not to address either that motion or the many similar dispositive motions filed by other defendants
and now pending in flood cases before the mass litigation panel. The Ashley case is currently
scheduled for trial as to liability in March 2006. Any judgment as to damages, if any, would be
determined in a separate trial following the liability phase.
Although it is too early in the litigation to express any meaningful opinion as to the
outcome, we believe we have a good defense to this action. In addition, pursuant to the Omnibus
Agreement, we have made a demand on Western Pocahontas Properties Limited Partnership for
indemnification with respect to any damages we might suffer up to $10 million.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 5. Other Information
None.
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Item 6. Exhibits
4.1
|
| Amendment No. 1 to Investor Rights Agreement, dated June 24, 2005, by and among FRC-WPP NRP Investment L.P., Natural Resource Partners L.P., NRP (GP) LP and GP Natural Resource Partners LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on June 28, 2005). | ||
4.2
|
| First Supplement to Note Purchase Agreements, dated as of July 19, 2005 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on July 20, 2005). | ||
4.3
|
| First Amendment, dated as of July 19, 2005, to Note Purchase Agreements dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on July 20, 2005). | ||
10.1
|
| Purchase and Sale Agreement by and between Steelhead Development Company, LLC and ACIN LLC, dated as of May 31, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 1, 2005). | ||
31.1*
|
| Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley. | ||
31.2*
|
| Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley. | ||
32.1**
|
| Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350. | ||
32.2**
|
| Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350. |
* | Filed herewith. |
** | Furnished herewith. |
28
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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.
NATURAL RESOURCE PARTNERS L.P. | ||||
By: NRP (GP) LP, its general partner | ||||
By: | GP NATURAL RESOURCE PARTNERS LLC, its general partner |
Date: August 3, 2005
By: | ||
/s/ Corbin J. Robertson, Jr. | ||
Corbin J. Robertson, Jr., | ||
Chairman of the Board and | ||
Chief Executive Officer | ||
(Principal Executive Officer) |
Date: August 3, 2005
By: | ||
/s/ Dwight L. Dunlap | ||
Dwight L. Dunlap, | ||
Chief Financial Officer and | ||
Treasurer | ||
(Principal Financial Officer) |
Date: August 3, 2005
By: | ||
/s/ Kenneth Hudson | ||
Kenneth Hudson | ||
Controller | ||
(Principal Accounting Officer) |
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EXHIBIT INDEX
4.1
|
| Amendment No. 1 to Investor Rights Agreement, dated June 24, 2005, by and among FRC-WPP NRP Investment L.P., Natural Resource Partners L.P., NRP (GP) LP and GP Natural Resource Partners LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on June 28, 2005). | ||
4.2
|
| First Supplement to Note Purchase Agreements, dated as of July 19, 2005 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on July 20, 2005). | ||
4.3
|
| First Amendment, dated as of July 19, 2005, to Note Purchase Agreements dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on July 20, 2005). | ||
10.1
|
| Purchase and Sale Agreement by and between Steelhead Development Company, LLC and ACIN LLC, dated as of May 31, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 1, 2005). | ||
31.1*
|
| Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley. | ||
31.2*
|
| Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley. | ||
32.1**
|
| Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350. | ||
32.2**
|
| Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350. |
* | Filed herewith. |
** | Furnished herewith. |